Marcellus Shale Safe Drilling Initiative Study: Part II

Marcellus Shale Safe Drilling Initiative Study: Part II
MARCELLUS SHALE SAFE DRILLING
INITIATIVE STUDY
PART II
INTERIM FINAL BEST PRACTICES
July 2014
Prepared By:
Maryland Department of the Environment
Maryland Department of Natural Resources
Prepared For:
Martin O’Malley, Governor
State of Maryland
Thomas V. Mike Miller, Jr., Senate President
Maryland General Assembly
Michael E. Busch, House Speaker
Maryland General Assembly
Prepared pursuant to Executive Order 01.01.2011.11
MARCELLUS SHALE SAFE DRILLING
INITIATIVE STUDY
PART II
INTERIM FINAL BEST PRACTICES
July 2014
Prepared By:
Maryland Department of the Environment
Maryland Department of Natural Resources
Prepared For:
Martin O’Malley, Governor
State of Maryland
Thomas V. Mike Miller, Jr., Senate President
Maryland General Assembly
Michael E. Busch, House Speaker
Maryland General Assembly
Prepared pursuant to Executive Order 01.01.2011.11
Contents
EXECUTIVE SUMMARY ..................................................................................... 1
SECTION I – ORGANIZATION OF THE REPORT............................................. 3
SECTION II – OVERVIEW .................................................................................... 5
A. MARCELLUS SHALE ........................................................................................... 5
B. DEVELOPMENTS IN MARYLAND .................................................................... 5
C. THE EXECUTIVE ORDER AND THE ADVISORY COMMISSION ................. 6
D. THE WORK OF THE ADVISORY COMMISSION ............................................... 7
SECTION III – COMPREHENSIVE GAS DEVELOPMENT PLANS ............... 10
A.
B.
C.
D.
E.
APPLICATION CRITERIA AND SCOPE .......................................................... 11
PLANNING PRINCIPLES ................................................................................... 11
PROCEDURE AND APPROVAL PROCESS ..................................................... 12
BENEFITS OF A COMPREHENSIVE GAS DEVELOPMENT PLAN ............. 13
THE SHALE GAS DEVELOPMENT TOOLBOX .............................................. 14
SECTION IV – LOCATION RESTRICTIONS AND SETBACKS..................... 17
A. LOCATION RESTRICTIONS AND SETBACKS .............................................. 17
B. SITING BEST PRACTICES ................................................................................. 23
SECTION V – PLAN FOR EACH WELL............................................................ 24
SECTION VI – ENGINEERING, DESIGN AND ENVIRONMENTAL
CONTROLS AND STANDARDS ........................................................................ 26
A. SITE CONSTRUCTION AND SEDIMENT AND EROSION CONTROL ........ 26
1.
The pad......................................................................................................... 26
2.
Tanks and containers.................................................................................... 27
3.
Pits and Ponds .............................................................................................. 27
4.
Pipelines ....................................................................................................... 27
5.
Road Construction ....................................................................................... 29
6.
Ancillary equipment..................................................................................... 29
B. TRANSPORTATION PLANNING ...................................................................... 29
C. WATER ................................................................................................................. 30
1.
Storage ......................................................................................................... 30
2.
Water withdrawal ......................................................................................... 31
3.
Water reuse .................................................................................................. 32
D. CHEMICAL DISCLOSURE ................................................................................. 32
E. DRILLING ............................................................................................................ 34
1.
Use of electricity from the grid .................................................................... 34
2.
Initiation of drilling ...................................................................................... 34
3.
Pilot hole ...................................................................................................... 35
4.
Drilling fluids and cuttings .......................................................................... 35
i
F.
G.
H.
I.
J.
K.
L.
M.
N.
O.
P.
Q.
R.
5.
Open hole logging ........................................................................................ 36
CASING AND CEMENT ..................................................................................... 37
1.
Requirements for casing and cement ........................................................... 37
2.
Isolation........................................................................................................ 38
3.
Cased-hole logging, Integrity testing and Pressure testing .......................... 39
BLOWOUT PREVENTION ................................................................................. 39
HYDRAULIC FRACTURING ............................................................................. 40
FLOWBACK AND PRODUCED WATER ......................................................... 40
AIR EMISSIONS .................................................................................................. 40
1.
Green Completion or Reduced Emissions Completion ............................... 41
2.
Flaring .......................................................................................................... 41
3.
Electricity from the grid ............................................................................... 41
4.
Engines ......................................................................................................... 41
5.
Storage tanks ................................................................................................ 42
6.
Top-down BAT ............................................................................................ 42
WASTE AND WASTEWATER TREATMENT AND DISPOSAL .................... 42
LEAK DETECTION ............................................................................................. 44
LIGHT ................................................................................................................... 44
NOISE ................................................................................................................... 45
INVASIVE SPECIES ............................................................................................ 46
SPILL PREVENTION, CONTROL AND COUNTERMEASURES AND
EMERGENCY RESPONSE ................................................................................. 47
SITE SECURITY .................................................................................................. 48
CLOSURE AND RECLAMATION BOTH INTERIM AND FINAL ................. 48
SECTION VII – MONITORING, RECORDKEEPING AND REPORTING ...... 50
SECTION VIII – MISCELLANEOUS RECOMMENDATIONS ........................ 52
A. ZONING ................................................................................................................ 52
B. FINANCIAL ASSURANCE ................................................................................. 52
C. FORCED POOLING ............................................................................................. 52
SECTION IX – MODIFICATIONS TO PERMITTING PROCEDURES ........... 53
SECTION X – IMPLEMENTING THE RECOMMENDATIONS ...................... 54
APPENDIX A – MEMBERS OF THE COMMISSION ..................................... A-1
APPENDIX B – COMMENTS OF THE ADVISORY COMMISSION ............ B-1
APPENDIX C – RESPONSE TO PUBLIC COMMENTS ................................. C-1
AIR EMISSIONS ................................................................................................. C-3
ANCILLARY INFRASTRUCTURE ....................................................................... C-9
CHEMICALS .................................................................................................... C-12
THE COMPREHENSIVE GAS DEVELOPMENT PLAN......................................... C-15
CONTAMINATION OF DRINKING WATER ....................................................... C-28
ii
ENVIRONMENTAL ASSESSMENT AND ENVIRONMENTAL
IMPACT STATEMENTS..................................................................................... C-36
EARTHQUAKES ............................................................................................... C-40
EMERGENCY RESPONSE ................................................................................. C-41
ENFORCEMENT AND INSPECTIONS ................................................................ C-45
ENGINEERING, DESIGN AND ENVIRONMENTAL CONTROLS
AND STANDARDS ............................................................................................ C-57
FORCED POOLING........................................................................................... C-67
IMPACTS ON CHESAPEAKE BAY .................................................................... C-67
INDIVIDUAL WELL PERMIT ............................................................................ C-69
LEGISLATION ................................................................................................. C-70
NOISE .............................................................................................................. C-73
PRE-DEVELOPMENT BASELINE DATA ............................................................ C-76
PROCESS ...................................................................................................... C-77
CLASSIFICATION OF WASTES UNDER THE RESOURCE
CONSERVATION AND RECOVERY ACT (RCRA)............................................... C-81
RISK ASSESSMENTS........................................................................................ C-84
SPREAD OF FRACTURES ................................................................................. C-85
STORMWATER MANAGEMENT....................................................................... C-95
STRINGENCY OF THE PROPOSED BEST PRACTICES ....................................... C-97
SURFACE IMPACTS AND SETBACKS ............................................................ C-105
TRUCK TRAFFIC ........................................................................................... C-129
WASTE DISPOSAL ......................................................................................... C-133
WATER USE .................................................................................................. C-138
WELL CASING AND CEMENT ........................................................................ C-144
APPENDIX D – MARCELLUS SHALE CONSTRAINT ANALYSIS............. D-1
APPENDIX E – MARCELLUS SHALE AND RECREATIONAL AND
AESTHETIC RESOURCES IN WESTERN MARYLAND ............................... E-1
APPENDIX F – UMCES-AL REPORT AND CROSS REFERENCES ............. F-1
APPENDIX G – JUSTIFICATION FOR EXPANSION OF THE AQUATIC
HABITAT SETBACK FROM 300 FT TO 450 FT ............................................. G-1
APPENDIX H – ACRONYMS ........................................................................... H-1
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EXECUTIVE SUMMARY
Governor O’Malley’s Executive Order 01.01.2011.11 established the Marcellus Shale
Safe Drilling Initiative. An Advisory Commission was established to assist State
policymakers and regulators in determining whether and how gas production from the
Marcellus Shale in Maryland can be accomplished without unacceptable risks of adverse
impacts to public health, safety, the environment, and natural resources. The State has not
yet determined whether gas production can be accomplished without unacceptable risk
and nothing in this report should be interpreted to imply otherwise.
The Executive Order tasks the Maryland Department of the Environment (MDE) and the
Department of Natural Resources (DNR), in consultation with the Advisory Commission,
with conducting a three-part study and reporting findings and recommendations. The
completed study will include:
i.
findings and related recommendations regarding sources of revenue and
standards of liability for damages caused by gas exploration and production;
ii.
recommendations for best practices for all aspects of natural gas exploration
and production in the Marcellus Shale in Maryland; and
iii.
findings and recommendations regarding the potential impact of Marcellus
Shale drilling in Maryland.
Part I of the study, a report on findings and recommendations regarding sources of
revenue and standards of liability, in anticipation of gas production from the Marcellus
Shale that may occur in Maryland, was completed in December 2011. This is the second
report, Part II of the study.
In preparation for the Part II report, MDE entered into a Memorandum of Understanding
with the University of Maryland Center for Environmental Science, Appalachian
Laboratory (UMCES-AL), to survey best practices from several states and other sources,
and to recommend a suite of best practices appropriate for Maryland. The UMCES-AL
recommendations were completed in February 2013 and made available to the Advisory
Commission and the public. Those recommendations and drafts of this report were
considered by the Advisory Commission at several meetings.
The Departments evaluated whether to add to, accept, reject, or modify the suggestions,
based on a number of factors, including comments from the Advisory Commission. A
draft of the Departments’ report (“Draft Report”) was made available for public comment
on June 25, 2013. The recommendations in the draft report were very similar to those in
the UMCES-AL Report. Where a UMCES-AL recommendation was rejected or
modified, an explanation was provided. The comment period closed on September 10,
2013. After consideration of the comments, the Departments submit this interim final
report on Part II of the study, Best Practices.
The most innovative recommendation in the UMCES-AL Report is to use comprehensive
planning for foreseeable gas development activities in an area rather than considering
each well individually. By considering the placement of well pads, roads, pipelines and
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other ancillary equipment for a large area, the efficiency of the operation could be
maximized while the impacts on local communities, ecosystems, and other natural
resources could be avoided or minimized. The UMCES-AL Report recommended that a
comprehensive plan be voluntary.
The Departments agree that a Comprehensive Gas Development Plan (CGDP) designed
to address the larger, landscape-level issues and cumulative effects offers significant
benefits to both the industry and the public. Except for a limited number of exploratory
wells, the Departments propose to make a CGDP mandatory in Maryland and a
prerequisite to an application for a well permit. The CGDP would be developed by the
company through a process that allows public participation and then submitted to the
State for approval. Once the CGDP is approved, applications for individual wells
consistent with the approved plan could be made.
Whereas the CGDP establishes the locations for well pads, roads, pipelines and other
ancillary equipment, the application for an individual well permit will require detailed
plans for all activities, from construction of the access road through closure and
restoration of the site. The elements of the plan must meet or exceed standards for
engineering, design and environmental controls that are recommended in this report.
These standards address activities from the initial construction of the access road and pad
through closure and restoration of the site. They address sediment and erosion control,
stormwater management, transportation planning, water acquisition, storage and reuse,
disclosure of chemicals, drilling, casing and cement, blowout prevention, hydraulic
fracturing, flowback and produced water, air emissions, wastewater treatment and
disposal, leak detection, light, noise, invasive species, spill prevention control and
emergency response, site security and closure and reclamation. These standards do not
preclude the use of new and innovative technologies that provide greater protection of
public health, the environmental and natural resources.
The report also makes recommendations relating to monitoring, recordkeeping and
reporting. Appendices provide additional information on specific subjects and include
comments of the Advisory Commission and a summary of and response to public
comments.
The issuance of this interim final report is not the end of the process for identifying best
practices. Additional information, including a report on public health and a risk
assessment1 currently in process, could result in the modification of the best practices in
this report or the addition of best practices. As technology improves, better practices are
likely to be identified. Maryland regulations could be amended to reflect the new best
practices or the new best practices could be required by provisions in an individual well
permit.
1
The risk assessment will assume that all the best practices in this report are adopted.
2
SECTION I – ORGANIZATION OF THE REPORT
The Maryland Departments of the Environment and Natural Resources acknowledge the
excellent work of the University of Maryland Center for Environmental Science –
Appalachian Laboratory (UMCES-AL), and in particular Keith N. Eshleman, Ph.D. and
Andrew Elmore, Ph.D., for their work in preparing Recommended Best Management
Practices for Marcellus Shale Gas Development in Maryland (the UMCES-AL Report).
The UMCES-AL Report is organized into ten chapters, each devoted to protecting one
aspect of the environment, natural resources, public health and safety. In order to
facilitate the incorporation of the recommendations into a regulatory and permitting
program, however, we have chosen to organize this report differently. Within each
section, the relevant UMCES-AL recommendations are listed by their alphanumeric
designation as it appears in the UMCES-AL Report. (The same UMCES-AL
recommendations may be referenced in multiple sections.) The remainder of the section
reflects the Departments evaluation.
Section II provides background information and an overview of activities in Maryland
related to the Marcellus Shale. In addition, it summarizes the work of the Advisory
Commission.
Section III focuses on comprehensive planning, particularly the concept of planning for
the extraction of gas in a large area in order to avoid adverse impacts and minimize those
that cannot be avoided. This comprehensive planning would occur before the issuance of
a permit to drill any well.
Section IV addresses restrictions on the locations of well pads, pipelines, access roads,
compressor stations, and other ancillary facilities. Some ecologically important areas,
recreational areas and sources of drinking water may be fully protected only if certain
activities are precluded there. In other cases, set back requirements may be sufficient.
This section also describes siting best practices.
Section V establishes requirements for planning documents for individual wells.
Section VI deals with engineering, design, and environmental controls and standards.
This includes, among other things, pad and access road design, the use of tanks rather
than ponds for storing wastewater, air pollution controls, casing and cementing standards,
integrity testing, emergency plans, waste disposal, and closure.
Section VII describes best practices for monitoring, recordkeeping and reporting. Preapplication monitoring and monitoring during drilling, well completion, and production
are addressed. The response to monitoring results that suggest impacts is also discussed.
Inspections and enforcement are included in this section.
Section VIII includes miscellaneous recommendations.
Section IX discusses modifications to the permitting process.
Section X is a roadmap for implementing the recommendations.
3
Included as Appendices are: the names of the Advisory Commission members, comments
of the Advisory Commission, the response to public comments, a constraint analysis, a
discussion of Marcellus shale and recreational and aesthetic resources in western
Maryland, a link to the UMCES-AL Report, a comparison of the UMCES-AL
recommendations with those of the Departments, an explanation for the chosen setback
from aquatic habitats, and a list of acronyms.
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SECTION II – OVERVIEW
A.
Marcellus Shale
Geologists have long known about the gas-bearing underground formation known as the
Marcellus Shale, which lies deep beneath portions of the Appalachian Basin, including
parts of Western Maryland. Until advances in horizontal drilling and high volume
hydraulic fracturing (HVHF) and the combination of these two technologies, few thought
that significant amounts of natural gas could be recovered from the Marcellus Shale.
Drilling in the Marcellus Shale using horizontal drilling and HVHF began around 2005 in
Pennsylvania and has accelerated rapidly.
The production of natural gas has the potential to benefit Maryland and the United States.
Tapping domestic sources could advance energy security for the United States. When
burned to generate electricity, natural gas produces lower greenhouse gas emissions than
oil and coal, which could help to reduce the impact of energy usage as we transition to
more renewable energy sources. The exploration for and production of natural gas could
boost economic development in Maryland, particularly in Garrett and Allegany Counties.
As gas production from deep shale and the use of HVHF has increased, however, so have
concerns about its potential impact on public health, safety, the environment and natural
resources. Although accidents are relatively rare, exploration for and production of
natural gas from the Marcellus Shale in nearby states have resulted in injuries, well
blowouts, releases of fracturing fluids, releases of methane, spills, fires, forest
fragmentation, damage to roads, and allegations of contamination of ground water and
surface water. Other states have revised or are in the process of reevaluating their
regulatory programs for gas production or assessing the environmental impacts of gas
development from the Marcellus Shale. A significant amount of research has been
completed on HVHF and gas production from the Marcellus Shale, but additional
research by governmental entities, academic organizations, environmental groups and
industry is currently underway focused on drinking water, public health, natural
resources, wildlife, community and economic implications, production technologies and
best practices.
B.
Developments in Maryland
The Maryland General Assembly has entrusted the permitting and regulation of oil and
gas exploration and development in Maryland to the Department of the Environment.
With a few notable exceptions, the statutory language is general and MDE is authorized
to promulgate rules and regulations and to place in permits conditions it deems
reasonable and appropriate to assure that the operations are carried out in compliance
with the law and provide for public safety and the protection of the State’s natural
resources. Md. Env. Code Ann., §§ 14-103 and 14-110. The Department’s regulations on
oil and gas wells have not been revised since 1993 and thus were written before recent
advances in technology and without the benefit of more recent research.
5
The Maryland Departments of the Environment (MDE) and Natural Resources (DNR)
have roles in the evaluation of natural gas projects. Each would be involved in any future
permitting decisions for drilling in the Marcellus Shale.
The mission of the Maryland Department of the Environment is to protect and restore the
quality of Maryland’s air, water, and land resources, while fostering smart growth,
economic development, healthy and safe communities, and quality environmental
education for the benefit of the environment, public health, and future generations. In
addition, MDE is specifically authorized by statute to issue permits for gas exploration
and production. The Department of the Environment is required to coordinate with the
Department of Natural Resources in its evaluation of the environmental assessment of
any proposed oil or gas well.
The Department of Natural Resources leads Maryland in securing a sustainable future for
our environment, society, and economy by preserving, protecting, restoring, and
enhancing the State’s natural resources. In addition, DNR owns or has conservation
easements on substantial acreage in the State, including western Maryland.
The first application for a permit to produce gas from the Marcellus Shale in Maryland
using horizontal drilling and HVHF was received in 2009.2 To address the need for
information to evaluate these permit applications properly, the Governor issued the
Marcellus Shale Safe Drilling Initiative in Executive Order 01.01.2011.11 on June 6,
2011.
C.
The Executive Order and the Advisory Commission
Executive Order 01.01.2011.11 directs MDE and DNR to assemble and consult with an
Advisory Commission in the study of specific topics related to horizontal drilling and
HVHF in the Marcellus Shale.3 The Advisory Commission is to assist State policymakers
and regulators in determining whether and how gas production from the Marcellus Shale
in Maryland can be accomplished without unacceptable risks of adverse impacts to public
health, safety, the environment, and natural resources. The Advisory Commission
includes a broad range of stakeholders. Members include elected officials from Allegany
and Garrett Counties, two members of the General Assembly, representatives of the
scientific community, the gas industry, business, agriculture, environmental
organizations, citizens, and a State agency. A representative of the public health
community was added in 2013. Appendix A is a list of the Commissioners.
The Executive Order tasks MDE and DNR, in consultation with the Advisory
Commission, with conducting a study and reporting findings and recommendations in
three reports. The Commission is staffed by DNR and MDE. The reports were to include:
(i) By December 31, 2011, a presentation of findings and related recommendations
regarding the desirability of legislation to establish revenue sources, such as a State-
2
Additional applications were received in 2011. Applications for a total of seven wells were received by MDE, but all have been
withdrawn. In general, interest in drilling has shifted to areas where not only natural gas but also natural gas liquids that are more
valuable, can be produced from formations. It is not likely that Maryland’s Marcellus shale contains natural gas liquids.
3
Although the Governor’s Executive Order is directed specifically at the Marcellus Shale and HVHF, there is a potential for gas
extraction from other tight shale gas formations, including the Utica Shale, and by well stimulation techniques other than HVHF. The
findings and conclusions regarding gas exploration in the Marcellus Shale may or may not apply to other formations and techniques.
6
level severance tax, and the desirability of legislation to establish standards of
liability for damages caused by gas exploration and production;
(ii) By August 1, 2012, recommendations for best practices for all aspects of natural
gas exploration and production in the Marcellus Shale in Maryland; and
(iii) No later than August 1, 2014, a final report with findings and recommendations
relating to the impact of Marcellus Shale drilling including possible contamination of
ground water, handling and disposal of wastewater, environmental and natural
resources impacts, impacts to forests and important habitats, greenhouse gas
emissions, and economic impact.
The first report4 on findings and recommendations regarding sources of revenue and
standards of liability, in anticipation of gas production from the Marcellus Shale that may
occur in Maryland, was completed in December 2011. The schedule was extended for the
second and third reports.
D. The Work of the Advisory Commission
The Governor announced the membership of the Advisory Commission in July, 2011,
and the Commission has met 28 times through May 2014. Most meetings were in
Allegany or Garrett Counties, but several were held in Hagerstown, Annapolis and
Baltimore. The Departments have provided written information and briefings to the
Advisory Commission on issues relating to HVHF. Speakers representing the scientific
community, industry and agencies from Maryland and other states have presented
information to the Advisory Commission and the Departments. The Commissioners were
able to visit active drilling sites. The Departments have consulted with the federal
government and neighboring states regarding policy, programmatic issues and
enforcement experiences. The Commissioners themselves, a well-informed and diverse
assemblage, shared information and brought their expertise to bear.
The Commission recognized the importance of obtaining background data on air and
water quality in advance of any drilling. DNR has begun collecting data to establish predrilling baseline conditions. Limited by existing funding and staff, DNR and MDE were
not able to fully implement the comprehensive baseline monitoring program
recommended by the Departments and the Advisory Commission in its Part I report.
DNR has, however, expanded and modified its monitoring program to include 12
continuous water monitoring sites chosen for their relevance to potential gas
development. DNR also began a volunteer partnership with Garrett County watershed
associations, Trout Unlimited and other citizens where volunteer stream waders are
collecting baseline water and biological data from over 70 stream segments. More
information on stream monitoring in the Marcellus shale region5 can be found online.
DNR conducted a natural resource assessment of Garrett County to identify high quality
streams known for biodiversity and brook trout resources, landscape values, ecological
resources, forest interior dwelling species habitats, areas supporting rare, threatened and
endangered plants and animals, community water supplies, State lands, trail networks,
recreational assets, and areas of particular scenic value that could be impacted, directly or
4
5
www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Meetings/Marcellus_Shale_Report_Part_I_Dec_2011.pdf
http://www.dnr.state.md.us/streams/marcellus.asp
7
indirectly, by drill pads, pipeline/road construction and use. The findings, Marcellus
Shale Gas Development in Maryland: A Natural Resource Analysis,6 were presented to
the Commission on February 27, 2012.
MDE funded the Maryland Geological Survey (MGS) to perform a limited study of
methane levels in drinking water wells in Garrett County. MGS evaluated methane
samples from 49 wells in 2012 and an additional 28 wells in 2013 in Garrett County and
western Allegany County and issued a report, Dissolved-Methane Concentrations in Well
Water in the Appalachian Plateau Physiographic Province of Maryland,7 in 2013.
The Departments, in consultation with the Advisory Commission, convened a committee
to evaluate necessary revisions to existing statutes and the need for new legislation to
address liability, revenue, leases and surface owner’s rights. The Departments and the
Advisory Commission coordinated with representatives of the House Environmental
Matters Committee and the Senate Education, Health and Environment Committee. This
effort is ongoing.
In the 2012 session of the General Assembly, a bill entitled Environment - Presumptive
Impact Areas -Contamination Caused by Gas Wells in Deep Shale Deposits (HB1123)
was passed establishing an area around a gas well within which it is presumed that
contamination of a drinking water well was caused by gas well activities if it occurred
within one year of the activities. Delegate Mizeur, a member of the Commission,
sponsored the bill.
In the 2013 session of the General Assembly, bills passed that had been introduced by
Senator George Edwards, a member of the Commission: Business Occupations – Oil and
Gas Land Professionals (SB766, HB828); and Environment – Gas and Oil Drilling –
Financial Assurance (SB854). Landmen will now have to register with the Department of
Labor, Licensing, & Regulation. The financial assurance bill lifts the cap on the closure
and reclamation bond and requires a minimum level of environmental impairment
insurance in addition to general comprehensive liability insurance.
Also in 2013, the Governor proposed and the legislature approved a supplemental Fiscal
Year 2013 appropriation that provided MDE with $1 million and DNR with $500,000 to
complete the studies required under the Executive Order. The Departments are using this
money, among other things, to expand the pre-drilling monitoring of air and water, and
undertake an economic study and a public health study.
In furtherance of developing Best Practices recommendations, MDE contracted with the
University of Maryland Center for Environmental Science, Appalachian Laboratory
(UMCES-AL), to survey best practices from several states and other sources, and to
recommend a suite of best practices appropriate for Maryland. The principal
investigators, Keith N. Eshleman, Ph.D. and Andrew Elmore, Ph.D., compiled best
practices from five states (Colorado, New York, Ohio, Pennsylvania, and West Virginia),
as well as the recommendations of expert panels and organizations. The survey was
completed and made available to the Commission. The report, Recommended Best
6
7
www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Eshleman_Elmore_Final_BMP_Report_22113_Red.pdf
www.mgs.md.gov/publications/report_pages/ADMIN_14-02-01.html
8
Management Practices for Marcellus Shale Development in Maryland8 (the UMCES-AL
Report), was made available to the Commission and the public in February 2013 and a
link to it is included as Appendix F. The Departments also charted a comparison of the
recommendations of UMCES-AL and the Departments; it is also included in Appendix F.
As the Departments reviewed that report and consulted with the Advisory Commission,
all of the recommendations in the UMCES-AL Report were considered. The Departments
evaluated whether to add to, accept, reject, or modify the recommendations based on a
number of factors, including the opinions of the Advisory Commission, the expertise of
Departmental staff, and judgments about environmental protection, technical
practicability, and administrative feasibility.
The draft best practices report (“Draft Report”) was made available for public comment
on June 25, 2013. The initial date for closing the comment period, August 9, 2013, was
extended to September 10, 2013. More than 4,000 comments were received. Having
considered all of the comments, including those of the Advisory Commission, the
Departments submit this final report on Part II of the study, Best Practices.
The issuance of this report is not the end of the process for identifying best practices.
Additional information, including a report on public health and a risk assessment9
currently in process, could result in the modification of the best practices in this report or
the addition of best practices. As technology improves, better practices are likely to be
identified. Maryland regulations could be amended to reflect the new best practices or the
new best practices could be required by provisions in an individual well permit. The State
has not yet determined whether gas production can be accomplished without
unacceptable risk and nothing in this report should be interpreted to imply otherwise.
8
9
http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Meetings/MAC_NaturalResourcesAnalysis.pdf
The risk assessment will assume that all the best practices in this report are adopted.
9
SECTION III – COMPREHENSIVE GAS DEVELOPMENT PLANS
UMCES-AL Report recommendation 1-A, 1-C, 1-G, 5-A, 5-A.1, 5-A.3, 5-F, 5-F.1, 6-A,
6-C, 6-D, 6-E, 6-F, 6-J, 7-A, 7-A.1, 7-D, 7-D.1, 8-A, 8-B, 8-E, 9-A, 9-A.1, 9-A.2, 9-A.3,
9-E, 9-E.1, 9-G, 10-B
The authors of the UMCES-AL Report suggest that the single most important
recommendation in their report is the comprehensive drilling plan. They recommend that
the State should institute a voluntary program whereby a company holding gas interests
could prepare and submit for State approval a comprehensive drilling plan for a large
geographic area before applying for any permit to drill a specific well. They suggested
that incentives could be offered, such as expedited processing of permits for individual
wells included in the comprehensive drilling plan.
The Departments agree that a comprehensive plan offers great advantages, but we
recommend that the program be mandatory rather than voluntary. In the Draft Report, we
proposed that Maryland require, as a prerequisite to the issuance of any permit to drill a
gas exploration, extension, or production well, that the prospective applicant first submit
a Comprehensive Gas Development Plan (CGDP). Commenters noted that basic
information that can only be obtained by an exploratory well would be necessary before a
company could write a CGDP. If a company were required to prepare a CGDP before
drilling exploratory wells, there would be a high likelihood that the information obtained
from exploratory wells would necessitate a substantively different CGDP.
The Departments are therefore proposing that one exploratory well can be drilled within a
circular area having a radius of 2.5 miles centered at the exploratory well. This area is
approximately 20 square miles. The exploratory well must comply with all of the location
restrictions, setbacks, and other requirements for an individual well permit, including two
years of predevelopment baseline monitoring and a rapid site assessment. No additional
wells, exploratory or production, can be drilled within that area until a CGDP has been
approved. Absent a determination by the Department that the exploratory well can be
connected to a transmission line without any adverse impact on wetlands, forest, or
nearby residents, the exploratory well cannot be converted to a production well until a
CGDP for that area is approved.
We believe that the program can be structured so that obtaining a CGDP is not unduly
burdensome to the applicant, allows industry the flexibility to respond to changing
conditions, and still achieves its purpose of reducing adverse and cumulative effects. The
CGDP will address the locations for activities, but not the well-specific requirements of
an individual permit. The processes, therefore, will not be duplicative.
The CGDP should address, at a minimum, all land on or under which the applicant
expects to conduct exploration or production activities over a period of at least the next
five years. The CGDP could be submitted by a single company or by more than one
entity for an assemblage of land in which multiple entities hold mineral rights. The
CGDP must address the locations of well pads, roads, pipelines and ancillary facilities
10
related to exploration or production activities from the identified land, but the CGDP is
not a commitment on the part of the applicant to install any of the facilities, or to proceed
in a particular sequence.
CGDPs provide an opportunity to address multiple aspects of shale gas development
from a holistic, broad-scale planning perspective rather than on a piecemeal, site-by-site
basis. By considering the entire project scope of a single company, or multiple companies
simultaneously, responsible energy development could proceed while minimizing public
health conflicts and addressing the concerns associated with maintaining the rural
character of western Maryland and protecting high value natural resources and resourcebased economies. To cite just one example, land disturbance could be minimized if
infrastructure were shared or located within the same right of way. Proactive, upfront
planning at a landscape scale provides the framework for evaluating and minimizing
cumulative impacts to the environmental, social and economic fabric of western
Maryland. The Departments agree that a CGDP process will be beneficial and
recommend that this be a mandatory prerequisite before any individual permit for a
production well would be issued. The associated recommendations from the UMCES-AL
Report, as listed as above, are generally accepted by the Departments for planning
guidelines. The outline below provides a conceptual framework.
A.
Application Criteria and Scope
1.
Companies intending to develop natural gas resources are required to submit a
CGDP for the area where the applicant may conduct gas exploration10 or production
activities and install supporting infrastructure (compressor stations, waste water treatment
facilities, roads, pipelines, etc.) for a period of at least five years.
2.
Companies whose geographic planning units overlap are encouraged to develop
integrated plans to improve use of existing and new infrastructure, to share or co-locate
infrastructure, and to minimize cumulative impacts.
3.
A company is not obligated to develop all the pads, wells or supporting
infrastructure identified in the plan.
4.
An approved CGDP will remain in effect for ten years, but one renewal for an
additional 10 years may be granted by MDE if the resource information is updated, and
the locations approved in the initial CGDP are not prohibited under any more stringent
location restrictions or setback requirements enacted after the approval of the initial
CGDP.
B.
1.
Planning principles
Use multi-well, clustered drilling pads to minimize surface disturbance.
2.
Comply with location restrictions, setbacks and other environmental requirements
of State and local law and regulations.
3.
Observe and comply with all location restrictions and setbacks in Section IV and
locate wells, pads and infrastructure to avoid, minimize and mitigate impact on public
health and human and natural resources.
10
One exploratory well can be drilled within a circular area having a radius of 2.5 miles centered at the exploratory well before a
CGDP is submitted.
11
4.
Preferentially locate operations on disturbed, open lands or lands zoned for
industrial activity.
5.
Co-locate linear infrastructure with existing roads, pipelines and power lines.
6.
Consider impacts from other gas development projects and land use conversion
activities and plan to minimize cumulative surface impacts.
7.
Avoid surface development beyond 2 percent of the watershed area in high value
watersheds. This threshold is based on the ecological sensitivity of specific aquatic
organisms within these high value watersheds. Other factors, as discussed in the location
restriction and setbacks section will also limit the location and extent of surface
development.
8.
Minimize fragmentation of intact forest, with particular emphasis on interior
forest habitat.
9.
The Departments will incorporate the concept of “noise sensitive locations” into
its review of the CGDP.
10.
Adhere to Departmental siting policies (to be developed) to guide pipeline
planning and direct where hydraulic directional drilling and additional specific best
management practices are necessary for protecting sensitive aquatic resources when
streams must be crossed.
11.
C.
Additional planning elements include
a)
Identification of travel routes.
b)
A generalized water appropriation plan that identifies the proposed sources and
amounts of water needed to support the plan.
c)
Sequence of well drilling over the lifetime of the plan that places priority on
locating the first well pads in areas removed from sensitive natural resource
values.
d)
Consistency with local zoning ordinances and comprehensive planning
elements.
e)
Identification of all federal, State and local permits needed for the activities.
Procedure and Approval Process
1.
An applicant with the right to extract natural gas shall prepare a preliminary
CGDP that best avoids and then minimizes harm to human, natural, social, cultural,
recreational and other resources, and mitigates unavoidable harm.
2.
The CGDP shall include a map and accompanying narrative showing the
proposed location of all planned wells, well pads, gathering and transmission lines,
compressor stations, separator facilities, access roads, and other supporting infrastructure.
3.
An applicant must conduct a geological survey of the area covered by the CGDP
to help identify historic gas wells and faults. At a minimum, the geological survey will
include location of all gas wells (abandoned and existing), current water supply wells and
springs, fracture-trace mapping, orientation and location of all joints and fractures and
12
other additional geologic information as required by the State. The applicant will be
required to submit the survey data to the State in a report with the application for the
CGDP.
4.
The State will develop a Shale Gas Development Toolbox that will include GIS
data and provide it to companies that wish to prepare a CGDP. The applicant’s
preliminary Environmental Assessment shall be based on the data in the Toolbox,
supplemented with other information as needed, including a rapid field assessment for
unmapped streams, wetlands and other sensitive areas. A detailed description of the shale
Gas Development Toolbox is provided in section E, below.
5.
State agencies and local government agencies review the CGDP, evaluate
opportunities for coordinated regulatory review and present comments to the applicant to
direct any needed alternative analyses for review. This review will be completed within
45 days of submission by the applicant of the CGDP.
6.
The public review and approval process is mandatory and will be initiated upon
request of the applicant following receipt of agency comments.
7.
A stakeholders group that includes the company, local government, resource
managers, non-governmental organizations, and surface owners will be convened; in a
facilitated process that shall not exceed 60 days, to discuss and improve the plan.
8.
The plan shall be presented at a public meeting by the applicant and the public
shall be allowed to comment on the plan.
9.
The applicant may further modify the plan based on alternatives analyses and
public comment before submitting it to the State for approval.
10.
In evaluating the CGDP, the State shall determine whether the plan conforms to
all regulatory requirements concerning location, and shall consider the plan and the
comments of the stakeholders and public.
11.
If the State determines that the CGDP conforms to regulatory requirements and,
to the maximum extent practicable, avoids impacts to natural, social, cultural,
recreational and other resources, minimizes unavoidable impacts, and mitigates
remaining impacts, the State shall approve the CGDP.
12.
Once the CGDP is approved, the entity may file a permit application that is
consistent with the plan for one or more wells.
13.
Significant modification to the original plan, such as a significant change in
location of a drilling pad, or the addition of new drilling pads, will require the submission
and approval of a modified CGDP application. Modifications that cause no surface
impact, such as the installation of additional wells on an existing pad or a change in the
sequence of development shall be approved by the State upon request of the applicant.
D.
Benefits of a Comprehensive Gas Development Plan
An approved, high quality CGDP could result in numerous benefits for all parties. These
benefits, particularly those related to improved coordination and expedited permit review,
are still under discussion among the review agencies, but could include:
13
1.
Better protection of natural, social, cultural, recreational and other resources, and
reduced cumulative impact.
2.
Early identification of alternatives to avoid, minimize and mitigate impacts to
wetlands and waterways , such as those associated with pipeline networks and road
construction, that require a comprehensive alternatives analysis scenario.
3.
Preliminary approval for drill pad locations, allowing the applicant to initiate
baseline monitoring and begin application for individual well permits.
4.
More efficient processing of other environmental approvals and permits, such as
air quality and water appropriation and use.
5.
Opportunities to implement mitigation actions prior to permit approval or in
advance of project development.
6.
Reduced need for multiple public hearings.11
7.
Reduced expense and risk associated with leveraging existing infrastructure and
centralizing various processing needs.
8.
E.
Reduced public use conflict and improved public good will.
The Shale Gas Development Toolbox
The toolbox will provide access to geospatial planning data necessary to address the
CGDP. The data will be available for download, and can be viewed through a publically
accessible interactive mapping application. The mapping application will be very similar
to DNR’s MERLIN online tool12 but will be tailored to include the geospatial data needed
for developing and evaluating the CGDP. Users of this data should be aware that actual
site and landscape conditions may not be accurately reflected in the mapped information.
Many fine scale environmental features, such as headwater streams or small wetlands, are
often not mapped. In addition, the effects of recent land use change may not be reflected
in the mapped datasets. For this reason, and to evaluate other site specific factors,
additional site assessment data will need to be collected by the applicant to meet the
requirements of the CGDP. The planning datasets that will be included in the toolbox
include those related to the elements discussed in Section IV. A. Location Restrictions
and Setbacks and in Section IV. B. Siting Best Practices. Additional datasets may be
added to improve the CGDP process.
1. Planning objective: Leveraging existing infrastructure.
a. State and county roads
b. Existing rights of way for gas lines and transmission lines
c. Land use/land cover data for identifying industrial land uses
2. Planning element: Location restrictions and setbacks that indicate where certain gas
development activities are restricted.
11
The CGDP does not in any way excuse compliance with any of the procedural or substantive requirements for other permits, and
citizens will be afforded all of their public participation rights, including hearing rights.
12
http://dnrweb.dnr.state.md.us/merlin/
14
a. Streams, rivers and flood plains – stream maps will include designated use
classifications
b. Wetlands
c. Steep slopes (> 15 percent)
d. Drinking water reservoirs and their watersheds
e. Irreplaceable Natural Areas (BioNet Tier 1 and 2 areas)
f. Cultural and historic areas, including National Registry sites
g. Local, State and federal parks
h. Wildlands
i. State forests and other DNR lands
j. Wild and scenic rivers
k. Scenic byways
l. Mapped limestone outcrops and known caves
m. Historic gas wells
n. Well head protection areas and source water assessment areas for public water
systems
o. Geological fault areas
3. Planning element: Additional siting criteria to guide avoidance, minimization and
mitigation of potential impacts.
a. Land use land cover for preferentially siting activities on open, disturbed land
or areas in industrial use and avoiding forested areas.
b. High value watersheds (Tier II, Brook trout and Stronghold watersheds)
where surface area impacts should not exceed the ecological threshold of
2 percent of the watershed area.
c. Forest interior dependent species (FIDS) habitat - large contiguous forest
patches important for supporting FIDS
d. Green Infrastructure Hub and Corridor network - a system of large habitat
areas connected to each other through corridors that are important for
allowing plant and animal migration.
e. Forests important for protecting water quality - forested areas that have
exceptional value for maintaining clean and cool water quality for streams and
rivers.
f. BioNet habitat areas - habitat important for wildlife and rare species. This
dataset includes Irreplaceable Natural Areas (Tier 1 and 2 areas) and other
important habitats (Tier 3, 4 and 5 areas).
g. GreenPrint Targeted Ecological Areas – high value lands and waters that are
eligible for State conservation funding through Program Open Space.
h. Recreational use considerations to minimize public use conflicts based on the
results of the participatory GIS workshop conducted in November of 2013.
i. Lands protected by conservation easements
j. Mapped underground coal mines
k. Aerial imagery – useful for evaluating actual ground conditions
l. Additional data layers as provided by the Department of Health and Mental
Hygiene related to public health concerns
15
4. Planning element: Identification of appropriate natural resource mitigation actions to
address unavoidable impacts. The Watershed Resources Registry Tool13 can be used
to identify potential mitigation options for restoration and conservation of stream
buffers, wetlands and upland forests. This tool has been developed by a consortium of
federal and State regulatory and non-regulatory agencies, including MDE and DNR.
13
watershedresourcesregistry.com
16
SECTION IV – LOCATION RESTRICTIONS AND SETBACKS
This section addresses restrictions on the locations of well pads14, pipelines, access roads,
compressor stations, and other ancillary facilities. Certain ecologically important areas,
recreational areas and sources of drinking water may only be fully protected if certain
activities are precluded there. Similar reasoning can be applied to the protection of
cultural and historic resources, where the presence of shale gas development
infrastructure will detract from the interpretative value and visitor experience.
Minimizing conflict with residential and community based uses is also an important
consideration in defining location restrictions. In addition to designating certain places or
features themselves “off limits”, many of these resources also require a minimum setback
distance to provide an additional buffer between the development activity and the
resource of concern. The setback distance will vary based on the resource of concern and
the nature of the disturbance. This section also describes additional avoidance,
minimization and mitigation criteria and siting best practices.
A.
Location Restrictions and Setbacks
UMCES-AL Report recommendations 1-E, 1-H, 1-I, 1-J, 4-A, 5-C, 5-C.1, 5-C.2, 5-C.3,
6-B, 8-F, 8-G, 9-C
Certain location restrictions and setbacks exist in current law and regulation and, with the
exception of the prohibition on locating a gas well within 2,000 feet of another gas well
in the same reservoir, these will not be lessened. In addition to a statutory prohibition
against drilling for gas or oil in the waters of the Chesapeake Bay, any of its tributaries,
or in the Chesapeake Bay Critical Area (Md. Env. Code §14-107), these are:
Table I-1: Existing Setback Requirements
Distance
(feet)
1,000
2,000
From
To
Waivers
Cite
Well
The boundary of the
property on which
the well is to be
drilled
Can be granted by the
Department if a well
location closer than
1,000 feet is necessary
due to site constraints.
Md. Env. Code
§14-112 and
COMAR
26.19.01.09 C
and D
Gas
Well
Existing gas well in
the same reservoir
Unless the Department is
provided with geologic
evidence of reservoir
separation to warrant
granting an exception
COMAR
26.19.01.09 E
The term “well pad” includes the area where drill rigs, pumps, engines, generators, mixers and similar equipment, fuel, pipes and
chemicals are located. It does not include temporary housing and employee parking lots.
14
17
1320
Oil
Well
Exiting oil well in
the same reservoir
1,000
Well
A school, church,
drinking water
supply, wellhead
protection area, or
an occupied
dwelling
Unless the Department is
provided with geologic
evidence of reservoir
separation to warrant
granting an exception
Unless written
permission of the owners
is submitted with the
application and approved
by the Department
COMAR
26.19.01.09 F
COMAR
26.19.01.09 G
The figure below illustrates the concept of location restrictions and setbacks that uses the
UMCES-AL recommendation for aquatic habitat. The resource of concern is a wetland.
UMCES-AL has recommended that the edge of
drill pad disturbance should be 300 feet or
greater from the wetland habitat. The drill pad
must be located outside of the restricted
resource and the required setback distance.
A preliminary analysis was conducted by DNR
to evaluate the effect of a subset of proposed
location restrictions and setbacks on the ability
to access Marcellus shale gas through horizontal
drilling (Appendix D: Marcellus shale constraint
analysis). The surface constraint factors selected
were those which were appropriate for a coarse,
landscape scale analysis. An average drill pad size of 4 acres was assumed. Under a
scenario that excluded drilling from the Accident gas storage dome and assumed an 8,000
foot horizontal drill length, approximately 94 percent of the Marcellus shale would be
accessible. In an effort to be conservative, the same analysis was run using a 4,000 foot
horizontal drill length, resulting in about 86 percent accessibility to the Marcellus shale
formation. This assessment supports the UMCES-AL suggestion that it is reasonable to
expect that shale gas resources can be broadly accessed while minimizing surface
disturbance, particularly in areas with sensitive resources. Setback recommendations
from the UMCES-AL Report, with the Departments’ changes, are provided in Table I-2
below.
Table I-2: Setback Recommendations from UMCES-AL Report with Adjustments
Recommended by the Departments
Distance
(feet)
2,000
From
Surface of the
ground
To
The target
formation
18
MDE and DNR Adjustment
2,000 vertical feet between the lowest
fresh water aquifer and the target
formation
300
Aquatic habitat
(defined as all
streams, rivers,
seeps, springs,
wetlands, lakes,
ponds, reservoirs,
and 100 year
floodplains)
Edge of drill
pad
disturbance15
450 feet16
600
Special conservation
areas (e.g.,
irreplaceable natural
areas, wildlands)
Edge of drill
pad
disturbance
Agree; apply not just to drill pad
locations but to all permanent surface
infrastructure
300
All cultural and
historical sites, State
and federal parks,
trails, wildlife
management areas,
scenic and wild
rivers, and scenic
byways
Edge of drill
pad
disturbance
Apply not just to drill pad locations
but to all permanent surface
infrastructure.
1,000
Mapped limestone
outcrops or known
caves
Borehole
Agree as to caves; for limestone
outcrops, reduce to a setback of 750
feet on the downdip side
1,000
Mapped
underground coal
mines
Borehole
Unnecessarily restrictive; alternative
approach recommended; see Section
VI-E
1,320
Historic gas wells
Any portion
of the
borehole,
including
laterals
Agree
1,000
Any occupied
building
Compressor
stations
Agree
1,000
Any occupied
building
Borehole
Change to from edge of drill pad
disturbance
Private ground water
wells
Borehole
Within 2,000 feet of a private
drinking water well; except that the
500
“Edge of drill pad disturbance” means the limit of disturbance as indicated on the erosion and sediment control plan for the
construction.
16
This distance shall be measured from the center of a perennial stream or from the ordinary high water mark of any river, natural or
artificial lake, pond, reservoir, seep or spring, determined as conditions exist at the time of the approved CGDP.
15
19
2,000
Public ground water
wells
Borehole
2,000
Public surface water
intakes
Borehole
well pad may be located between
1,000 and 2,000 feet of a private
drinking water well if the applicant
demonstrates through a
hydrogeologic study that the
proposed well pad is not upgradient
of the private drinking water well and
the owner of the private drinking
water well consents. Change
borehole to edge of drill pad
disturbance.
a. Within 1,000 feet of a wellhead
protection area or a source water
assessment area for a public water
system for which a Source Water
Protection Area (SWPA) has been
delineated. b. Within 1,000 feet of
the default wellhead protection area
for public water systems for which a
wellhead protection area has not been
officially delineated. [For public
water systems that withdraw less than
10,000 gpd from fractured rock
aquifers the default SWPA is a fixed
radius of 1000 feet around the water
well(s).] Change from borehole to
edge of drill pad disturbance
Within 1,000 feet of a source water
assessment area for a public water
system for which a SWPA Area has
been delineated. Change from
borehole to edge of drill pad
disturbance
The Departments propose the following modifications and additions that were based on
the subject matter expertise of the agencies.
1.
Well pads shall not be constructed on land with a slope > 15 percent before
grading. This was recommended in the report, but not included as a key recommendation.
2.
Setback distances may be expanded on a case by case basis if the area includes
steep slopes or highly erodible soils.
3.
The setback distance from aquatic habitat (defined as all streams, rivers, seeps,
springs, wetlands, lakes, ponds, reservoirs, and 100 year floodplains) has been expanded
to 450 feet. Based on additional literature review documented in Appendix G, the setback
was expanded to provide the necessary level of protection for biodiversity (with a focus
20
on aquatic biodiversity), ensure sufficient corridor width needed for terrestrial wildlife
movement and forest interior-dwelling bird species, and reduce the visual, noise, and
light impacts of gas extraction operations in close proximity to aquatic habitats.
4.
The setback from a spring that is used as the source of domestic drinking water by
the residents of the property on which the spring is located, measured from spring to the
edge of the well pad, shall extend to all lands at an elevation equal to or greater than the
spring discharge elevation, but not to exceed 2,500 feet unless a delineation of the
recharge area prepared by a registered geologist, with a report and data supporting an
alternate area, is submitted to the Department and the Department approves an alternative
area.
5.
The restrictions for setbacks from limestone outcrops to the borehole has been
expanded to 750 feet (from the recommended 500 feet in the draft report) and to apply
only on the downdip side of the formation.
There is no need to adhere to
setbacks on the updip side because
the limestone formation – the
Greenbriar – will not be
encountered (see figure to left).
This setback recommendation was
established to avoid karst features.
However, the Maryland Geological
Survey states that most limestone in
Garrett County is not karst, but
when these features do occur, they
rarely penetrate below 100 – 200
feet from the surface. In Garrett
County, these formations generally dip at 15-20 degrees, while the beds in Allegany
County dip at steeper angles. Using a 200 foot depth for potential karst development and
a 15 degree dip as a conservative estimate, a 750 foot setback on the downdip side of the
limestone outcrop would be sufficiently protective. The State originally proposed a 500 ft
setback which was based on the steeper dip angles in Allegany County. This was
expanded to 750 ft upon consideration of the dip angles in Garrett County.
6.
Setbacks for known and discovered caves should remain at 1000 feet because of
the biological resource sensitivity and the potential for ground water contamination.
7.
Restrictions for setbacks from mapped underground coal mines to the borehole
are modified. MDE’s mining program notes that Maryland’s deep coal mines may cover
thousands of acres, are only several hundred feet deep, and can be safely cased through,
particularly if pilot holes are drilled to identify these features and drilling processes are
modified to address the known hazards. A setback of 1000 feet is unnecessarily
restrictive. Instead the Departments recommend pre-drill planning as an alternative which
involves careful site evaluation and pilot hole investigations. See Section VI-E for a
description on pre-drill planning.
8.
All surface disturbance for pads, roads, pipelines, ponds and other ancillary
infrastructure will be prohibited on State owned land, unless DNR grants permission.
21
9.
To more fully protect sources of drinking water, a well pad cannot be located:
a. Within 1,000 feet of a wellhead protection area or a source water
assessment area for a public water system for which a Source Water
Protection Area (SWPA) has been delineated.
b. Within 1,000 feet of the default wellhead protection area for public water
systems for which a wellhead protection area has not been officially
delineated. (For public water systems that withdraw less than 10,000 gpd
from fractured rock aquifers the default SWPA is a fixed radius of 1000
feet around the water well(s).)
c. Within 2,000 feet of a private drinking water well; except that the well pad
may be located between 1,000 and 2,000 feet of a private drinking water
well if the applicant demonstrates through a hydrogeologic study that the
proposed well pad is not upgradient of the private drinking water well and
the owner of the private drinking water well consents.
d. Within the watersheds of any of the following reservoirs:
i. Broadford Lake
ii. Piney Reservoir
iii. Savage Reservoir
10.
Drill pad location restrictions and setbacks listed in Table 1-1 have been extended
to all gas development activities resulting in permanent surface alteration that would
negatively impact natural, cultural and historic resources. This includes permanent roads,
compressor stations, separator facilities and other infrastructure needs. This expansion
applies to aquatic habitat, special conservation areas, cultural and historical sites, State
and federal parks and forests, trails, wildlife management areas, wild and scenic rivers
and scenic byways.
11.
DNR will develop new maps of public outdoor recreational use areas to consider
whether additional recreational setbacks are warranted and to inform mitigation measures
for minimizing public use conflicts. DNR conducted a participatory GIS workshop in
November of 2013 to develop these new maps, focusing on the recreational amenities of
lands in Garrett and Allegany Counties that co-occur with the Marcellus shale extraction
region.
The proposed recreational setback from Marcellus shale gas infrastructure is a minimum
of 300 feet with additional setback considerations for noise, visual impacts and public
safety. Maryland has a number of well-developed and nationally-recognized networks of
scenic and historic byways and hiking and water trails that provide opportunities for the
public to experience nature, cultural and historical features and the outdoors through
unique vistas and long-distance travel routes. The location and features that make these
routes unique (e.g. vistas, through-trail hikes, canopy cover) should be considered during
setback discussions. Additional factors will include hunting and fishing activities, light,
odor and other issues that would affect public use and enjoyment of these resources. A
more detailed discussion of these issues and concerns is provided in Appendix E:
Marcellus Shale and Recreational & Aesthetic Resources in Western Maryland. The
22
participatory GIS workshop was conducted with facility managers, friends groups,
frequent visitors, and other stakeholders. The maps generated from these discussions and
workshops will be included in the Shale Gas Development Toolbox and used to inform
comprehensive gas development plans, setback considerations, mitigation measures and
timing of shale gas development activities.
12.
For good cause shown and with the consent of the landowner protected by the
setback, MDE may approve exceptions to the setback requirements.
B.
Siting Best Practices
UMCES-AL Report recommendations 3-B, 4-D, 5-A.2, 6-J.2, 6-J.4, 8-C, 8-D, 8-H, 9-G,
9-H, 10-A, 10-C, 10-D
This section also includes best practices recommended for siting pipelines, access roads
and other supporting infrastructure. The Departments generally accept the proposed siting
best practices with the following modifications and additions.
1. Forest mitigation that is required to meet a no-net-loss of forest standard will be
evaluated differently based on whether the loss is temporary or permanent.
2. Site-specific viewshed analysis should be conducted (as recommended by
UMCES-AL), but temporary and permanent impacts will be evaluated differently.
3. Conservation of high value forest land through easements or fee-simple
acquisitions should be considered as an additional mitigation option for
implementing the no-net-loss of forest recommendation, particularly since
reforestation options in western Maryland locations may be limited. Conservation
banking may also be an additional mechanism to meet forest conservation
mitigation.
4. DNR will provide additional GIS conservation planning data layers and guidance
for avoiding, minimizing and mitigating impact to aquatic and terrestrial high
priority conservation areas. These data layers will be included in the Shale Gas
Development Toolbox described in Section III-E.
5. Stream crossings will avoid impact to brook trout spawning beds.
6. Operations, water withdrawals and infrastructure siting should avoid thermal
impacts to cold water streams.
The setback and other recommendations provide a high level of protection to Tier II
waters from MSGD activities. MDE will consider whether additional anti-degradation
protections are necessary for MSGD when it revises its anti-degradation regulations.
23
SECTION V – PLAN FOR EACH WELL
UMCES-AL Report recommendations 1-A, 3-A, 4-B
For each well, the applicant for a drilling permit shall prepare and submit to MDE, as part
of the application, a plan for construction and operation that meets or exceeds the
standards and/or individual planning requirements for Engineering, Design and
Environmental Controls set forth in Section VI. In preparing the plan, the applicant shall
consider all relevant API Standards and Guidance Documents, including normative
references, and, if the plan fails to follow a minimum requirement of a relevant API
standard, the plan must explain why and demonstrate that the plan is at least as protective
as the minimum requirement. The Department will clarify in the application form, or
instructions for that form, the type of information and level of detail that must be
addressed in the application for an individual well permit. The plan must address, at a
minimum,
1. Completing the Environmental Assessment
This effort includes all environmental assessment baseline monitoring and site
characterization required as a prerequisite for issuing individual well permits.
These are activities that would be initiated after the CGDP has been approved and
require site-specific, field scale assessment and monitoring.
2. Constructing the pad, containment structures, access roads and other ancillary
facilities
3. Method of providing power to equipment
4. Acquisition of water
5. Evaluation of potential flow zones
6. Identification and evaluation of shallow and deep hazards
7. Pore pressure/fracture gradient/drilling fluid weight
8. Monitoring and maintaining wellbore stability
9. Lost circulation
10. Casing
11. Cementing
12. Drilling fluids
13. Wellbore hydraulics
14. Barrier design
15. Integrity and pressure testing
16. Blow out protection
24
17. Contingency planning
18. Communications plan, including communication with contractors and
subcontractors and transfer of information upon shift change
19. Site security
20. Noise
21. Storage, treatment and disposal of water, wastewater, fuel and chemicals
22. Road construction and maintenance
23. Transportation planning, including the identification of routes to be traveled in
Maryland by heavy duty trucks and tractor trailers coming to or leaving the pad
site
24. Spill prevention, control and countermeasures, and emergency response
25. Invasive species
26. Waste handling, treatment and disposal
27. Monitoring during well production to detect well problems and failure of casing
or cement
28. Reclamation
29. Site specific visual impact assessment and mitigation
The applicant will be required to notify the owners of any property within 2,500 feet that
an application has been filed.
A suggestion has been made by some Commissioners that there be a formal process by
which other State and local government agencies could review and comment on the
application for an individual well permit. Because interagency issues will relate
principally to the location of the well pad, access roads, pipelines and other infrastructure,
review by other State and local government agencies would be more appropriate and
effective at the time of the CGDP, not the individual well permit. The Departments
recommend that the appropriate staff from specific agencies be invited to participate in
the CGDP development. The Departments plan to address coordination with local
government agencies on specific topics, such as transportation planning and emergency
response, through the standards set out in Section VI.
In the event that an application is make for an exploratory wells before a CGDP has been
submitted and approved, MDE will notify relevant State agencies and the County and
municipality in which the proposed exploratory well is to be located and provide an
opportunity to review the application and comment. Relevant State agencies will include
DNR and the Maryland Departments of Agriculture, Planning, and Health and Mental
Hygiene.
25
SECTION VI – ENGINEERING, DESIGN AND ENVIRONMENTAL CONTROLS
AND STANDARDS
The standards in this section do not preclude the use of new and innovative technologies
that provide greater protection of public health, the environmental and natural resources.
Practices used in shale gas development continue to evolve and improve. Exceptions to
these requirements will be considered if the new technology can be demonstrated to
assure equal or greater protection.
A.
Site Construction and Sediment and Erosion Control
UMCES-AL Report recommendations 4-E, 4-F, 4-G, 4-I, 5-B, 5-B.1, 6-G, 6-J, 6-J.1, 6-J,
6-K, 9-F
The proper construction of drilling pads, roads, pipelines, tanks, pits and ponds, roads,
and ancillary equipment is critical for eliminating or minimizing the risk of release of
pollutants to the environment from spills, accidents, and runoff of contaminated
stormwater. Current Maryland statutes and regulations on oil and gas wells are nearly
silent on design and construction requirements, except for pits and tanks.17 The
regulations require an approved stormwater management plan and sediment and erosion
control plan, but do not establish any requirements specific to oil and gas operations.18 As
these plans are written to address the requirements of shale gas development, training of
staff who review and approval the plan may be required.
1.
The pad
The pad is the center of activity during drilling and HVHF. Not only are the drill rig and
vertical borehole there, but the pad is also the site for storing fuel and chemicals,
handling drilling mud and cuttings, mixing and pressurizing hydraulic fracturing fluid,
mixing and pumping the cement, and handling flowback and produced water. The “well
pad” includes the area where drill rigs, pumps, engines, generators, mixers and similar
equipment, fuel, pipes, chemicals and wastes are located. It excludes temporary housing
and employee parking lots. Pollutants released19 on the pad could enter the environment
by infiltrating through the pad, running off the pad, or being washed from the pad by
precipitation. The UMCES-AL Report recommended closed loop drilling systems on
“zero-discharge” pads, containment of stormwater from the pad, and storage of all liquids
(except fresh water) in watertight, closed tanks inside secondary containment. The
Departments agree.
No discharge of potentially contaminated stormwater or pollutants from the pad shall be
allowed. Drill pads must be underlain with a synthetic liner with a maximum hydraulic
conductivity of 10-7 centimeters per second and the liner must be protected by decking
material. Spills on the pad must be cleaned up as soon as practicable and the waste
material properly disposed of in accordance with law. The drill pad must be surrounded
17
COMAR 26.19.01.10 J through K.
COMAR 26.19.01.06C (12) and (13).
19
Airborne releases are considered separately.
18
26
by an impermeable berm such that the pad can contain at least the volume of 4.0 inches
of rainfall within a 24 hour period. The berm may be made impermeable by extension of
the liner. Collected stormwater may be used for hydraulic fracturing, but prior to use, it
must be stored in tanks and not in a pit or pond. In addition, the design must allow for the
transfer of stormwater and other liquids that collect on the pad to storage tanks on the pad
or to trucks that can safely transport the liquid for proper disposal. The collection of
stormwater and other liquids may cease only when all potential pollutants have been
removed from the pad and appropriate, approved stormwater management can be
implemented.
2.
Tanks and containers
Tanks shall be above ground, constructed of metal or other material compatible with the
contents, and lined if necessary to protect the metal from corrosion from the contents.
Except for tanks used in a closed loop system for managing drilling fluid and cuttings,
which may be open to the atmosphere, tanks shall be closed and equipped with pollution
control equipment specified in other sections of this report. Tanks and containers shall be
surrounded with a continuous dike or wall capable of effectively holding the total volume
of the largest storage container or tank located within the area enclosed by the dike or
wall. The construction and composition of this emergency holding area shall prevent
movement of any liquid from this area into the waters of the State.
3.
Pits and Ponds
The UMCES-AL Report does not make recommendations for the construction of pits and
ponds, but recommends that they should be used only to collect or store fresh water; all
other material shall be stored in tanks. The Departments agree.
Current Maryland regulations require pits and ponds shall (a) have at least 2 feet of
freeboard at all times; (b) be at least 1 foot above the ground water table; (c) be
impermeable; (d) allow no liquid or solid discharge of any kind into the waters of the
State; and (e) provide for diverting surface runoff away from the pit or pond. Dikes
associated with pits must be constructed and maintained in accordance with standards and
specifications for soil and erosion sediment control. In addition they must be constructed
of compacted material, free of trees and other organic material, and essentially free of
rocks or any other material which could affect their structural integrity; and the dikes
must be maintained with a slope that will preserve their structural integrity; COMAR
26.19.01.10J and K. The Departments judge that the current regulations are sufficient for
fresh water storage.
4.
Pipelines
Gathering lines are pipelines that bring gas to a central facility or transmission line.
Transmission lines are interstate lines that transport gas long distances. The federal and
state governments share responsibility for gas pipelines. State and local laws address
pipeline placement as a construction activity that must comply with erosion and sediment
control plans and stormwater management. In addition, if pipelines cross wetlands or
waterways, additional permits may be required.
The United States Department of Transportation, Pipeline and Hazardous Materials
Safety Administration (PHMSA), Office of Pipeline Safety (OPS), has overall regulatory
responsibility for hazardous liquid and gas pipelines in the United States that fall under
27
its jurisdiction. OPS regulates and inspects hazardous liquid and gas interstate operators
in Maryland. Through certification by OPS, the State of Maryland regulates and inspects
the operators having intrastate gas and liquid pipelines. This work is performed by the
Pipeline Safety Division of the Maryland Public Service Commission.
Onshore natural gas gathering lines are classified by the federal government based upon
the number of buildings intended for human occupancy that lie within 220 yards on either
side of the centerline of any continuous one mile length of pipeline. If there are fewer
than 10 such buildings, the gathering lines are not federally regulated. They are
sometimes referred to as “rural gas gathering lines” In Maryland, the Pipeline Safety
Division of the Maryland Public Service Commission (PSC) regulates and inspects
intrastate gas and liquid pipelines. It appears that the PSC has not established any
standards for the location, materials, construction or testing of gathering lines beyond the
federal standards..
In the past, gathering lines were generally small diameter and did not operate under high
pressure. PHMSA has recognized that lines being put into service in shale plays like the
Marcellus are generally of much larger diameter and operating at higher pressure than
traditional rural gas gathering lines, increasing the concern for safety of the environment
and people near operations. Because they are unregulated, the PHMSA had limited
information about pipeline construction quality, maintenance practices, location and
pipeline integrity management. It is in the process of collecting new information about
gathering pipelines in an effort to better understand the risks they may now pose to
people and the environment. If the data indicate a need, PHMSA may establish new,
safety requirements for large-diameter, high-pressure gas gathering lines in rural
locations.
In the absence of existing federal or Maryland regulation of rural gathering lines, the
Departments recommend that, as a best practice, except for those oil and/or natural gas
pipelines covered by the Hazardous Materials Transportation Act (49 U.S.C. sections
1802 et seq.) or the Natural Gas Pipeline Safety Act (49 U.S.C. sections 1671 et seq.), all
pipelines utilized in the actual drilling or operation of oil and/or natural gas wells, the
producing of oil and/or natural gas wells, and the transportation of oil and gas, shall
comply with the following standards for material and construction:
a. The owner and operator of any pipeline shall participate as an “ownermember” as that term is defined in the Maryland Public Utilities Code,
Section 12-101, in a one-call system, which in Maryland is generally known
as the “Miss Utility” program. Upon the request of someone planning to
excavate in the area, the locations of these pipelines could be marked so that
the digging could avoid them.
b. All pipelines and fittings appurtenant thereto used in the drilling, operating
or producing of oil and/or natural gas well(s) shall be designed for at least
the greatest anticipated operating pressure or the maximum regulated relief
pressure in accordance with the current recognized design practices of the
industry.
28
5.
Road Construction
The UMCES-AL Report makes several recommendations about roads. Wherever
possible, existing roads should be used. Where new private road construction for
Marcellus shale activities in Maryland is necessary, it should follow guidelines issued by
the Pennsylvania Department of Conservation and Natural Resources. The guidelines: (1)
recommend utilizing materials and designs (e.g., crowning, elimination of ditches) that
encourage sheet flow as the preferred drainage method for any new construction or
upgrade of existing gravel roadways; (2) provide specific recommendations about
aggregate depth, type, and placement; and (3) promote the use of geotextiles as a way of
reducing rutting and maintaining sub-base stability. Erosion should be controlled and
damage to environmentally sensitive areas should be avoided. The authors opine that one
of the best ways to minimize the risk of road failures is to selectively schedule hauling
operations to avoid or minimize traffic during the spring thaw and other wet weather
periods. They further recommend that where stream crossings are unavoidable, the design
incorporate bridges or arched culverts to minimize disturbance of streambeds.
The Departments agree that roads constructed by private parties for access to gas
exploration and production facilities should avoid adverse environmental impacts and
minimize those that cannot be avoided. The location of roads will be evaluated during the
review of the Comprehensive Development Plan. Sediment and erosion control plans and
stormwater management plans will provide assurance that erosion will be controlled.
The UMCES-AL Report recommended the standards used by the Pennsylvania
Department of Conservation and Natural Resources, Bureau of Forestry, for roads in
leased State forest land. These standards are contained in Guidelines for Administering
Oil and Gas Activity on State Forest Lands.20 The Bureau of Forestry works closely with
The Pennsylvania State University’s Center for Dirt and Gravel Road Studies21 to
identify and adopt best practices for road maintenance and construction. The Center
makes a large amount of information about unpaved roads available on its website,
including technical bulletins. The Departments recommend that the design, construction
and maintenance of unpaved roads be at least as protective of the environment as the
standards adopted by the Bureau of Forestry.
6.
Ancillary equipment
Ancillary equipment includes gathering and boosting stations, glycol dehydrators and
compressor stations. A gathering and boosting station collects gas from multiples wells
and moves it toward the natural gas processing plant. Glycol dehydrators are used to
remove water from natural gas to protect the systems from corrosion and hydrate
formation. Compressor stations are placed along pipelines as necessary to increase
pressure and keep the gas moving. The location of compressors will be addressed in the
CGDP. Ancillary equipment is addressed in Section VI J and N (Air Emissions and
Noise).
B.
Transportation Planning
UMCES-AL Report recommendations 7-A, 7-D, 7-D.1, 7-D.2, 8-E, 9-A.4, 9-E, 9-E.1
20
21
http://www.dcnr.state.pa.us/cs/groups/public/documents/document/dcnr_004055.pdf
www.dirtandgravel.psu.edu/
29
In addition to road construction standards, timing of transportation activities and
addressing road damage are necessary elements of transportation planning. The State and
most counties have existing programs to allow for emergency transport of heavy or
oversized equipment during off-hour periods. The Departments accept the proposed
transportation planning recommendations with the following modifications and additions
to minimize use conflicts and provide adequate mitigation for road damage.
State public land managers should coordinate the timing of oil and gas activities with the
operator to avoid public conflict and to minimize damage to roads on public lands. Public
land managers should consider suspending activities requiring heavy trucking during:
1. Periods of heavy public use such as hunting season or trout season
2. Weather conditions that make the roads impassable
3. Traditionally wet periods when road damage is most probable
4. During the spring frost breakup
Note: Trucking should be closely monitored during high-use and wet periods if it is not
possible to suspend activities.
Applicants must coordinate with county and/or municipal offices to avoid truck traffic
under the following conditions:
1. During times of school bus transport of children to and from school locations.
7. During public events and festivals
Local jurisdictions are encouraged to develop adequate transportation plans.
Heavy equipment should be moved by rail, if available, to the maximum extent
practicable to protect road systems and prevent accidents.
All trucks, tankers and dump trucks transporting liquid or solid wastes must be fitted with
GPS tracking systems to help adjust transportation plans and identify responsible parties
in the case of accidents/spills.
Applicants shall be required to enter into agreements with the county and/or municipality
to restore the roads which it makes use of to the same or better condition the roadways
had prior to the commencement of the applicant’s operations, and to maintain the
roadways in a good state of repair during the applicant’s operations. The agreement may
mandate that the applicant post bond.
C.
Water
UMCES-AL Report recommendations 4-G, 4-J, 6-H.1, 6-H.2
1.
Storage
The UMCES-AL Report recommended that the Maryland regulations should specifically
address water storage, that impoundments may be used for storing freshwater, and that
temporary pipelines should be considered instead of trucks for transporting water. The
Departments agree that only freshwater should be stored in impoundments and would
permit either centralized freshwater impoundments or impoundments serving a single
well pad, provided the impoundment meets standards for safe construction (refer to Pits
30
and Ponds, above). Applicants for permits are encouraged to propose using temporary
pipelines for the transfer of fresh water to a drill site.
2.
Water withdrawal
The UMCES-AL Report recommends that Maryland revise its oil and gas permitting
regulations to explicitly address water withdrawal issues. In particular, they recommend a
quantitative analysis of acceptable water withdrawals to ensure that all users of the
resource are protected and that water withdrawal should occur only from the region’s
large rivers and perhaps from some reservoirs. In addition, the authors recommend that
precautions be taken to avoid the introduction of invasive species. For example, they
recommend an analysis of any invasive species that may be present in the source water
and power washing of the withdrawal equipment before it is removed from the
withdrawal site.
The Departments agree that practices are necessary to control invasive species. They are
addressed in Section VI O (Invasive Species). The Departments do not see a need to add
water appropriation provisions in MDE’s oil and gas regulations because current
Maryland laws and regulations protect other users of the water resource and the resource
itself.
The Maryland legislature has determined that the appropriation or use of surface or
ground water must be controlled in order to conserve, protect, and use water resources of
the State in the best interests of the people of Maryland. This control provides for the
greatest possible use of waters in the State, while protecting the State's valuable water
supply resources from mismanagement, abuse, or overuse. Private property owners have
the right to make reasonable use of the waters of the State which cross or are adjacent to
their land. For the benefit of the public, the Department acts as the State's trustee of its
water resources. Maryland follows the reasonable use doctrine to determine a person's
right to appropriate or use surface or ground water. A ground water appropriation or use
permit or a surface water appropriation or use permit issued by MDE authorizes the
permittee to make reasonable use of the waters of the State without unreasonable
interference with other persons also attempting to make reasonable use of water. The
permittee may not unreasonably harm the water resources of the State. COMAR
26.17.06.02.
Current Maryland statutes and regulations on water withdrawal, with certain exceptions
not relevant here, require MDE approval and issuance of an appropriation permit before a
person can withdraw any surface water, or more than 5,000 gallons per day (gpd) of
ground water as an annual average. Appropriation requests for an annual average
withdrawal of more than 10,000 gpd (as a new request or increase) may be required to
perform aquifer testing and other technical analyses. All applicants proposing a new use
of increase of 10,000 gpd are required to include certified notification of contiguous
property owners and certification of compliance with the State plumbing code and
requirements for water conservation technology. In addition, requests for an annual
average withdrawal of more than 10,000 gpd as a new request or increase are advertised
for a public information hearing.
Because the thresholds for requiring a permit are low, it is unlikely that anyone could
obtain a sufficient amount of water for HVHF without first obtaining a water
31
appropriation permit. The Departments believe that the substantive criteria for evaluating
applications for water appropriation are adequate to address water withdrawals for
Marcellus shale drilling and HVHF. These criteria are set forth in COMAR 26.17.06.05
and include impact on other users and the waters of the State, and the aggregate changes
and cumulative impact that the particular request and future appropriations in an area
may have on the waters of the State. The Department of the Environment has the
authority to include protective provisions in permits. COMAR 26.17.06.06.
3.
Water reuse
This topic is further discussed under Wastewater Treatment and Disposal, below. The
UMCES-AL Report recommended that Maryland should include “a very strong
preference” for onsite recycling of wastewater over treatment at a centralized facility,
because this would decrease truck transport and associated impacts. The Departments
agree.
Flowback and produced water shall be recycled to the maximum extent practicable.
Unless the applicant can demonstrate that it is not practicable, the permit shall require
that not less than 90 percent of the flowback and produced water be recycled, and that the
recycling be performed on the pad site of generation.
D.
Chemical Disclosure
UMCES-AL Report recommendations 4-H
The recommendations about disclosure of chemicals in the UMCES-AL Report related
specifically to response to chemical emergencies, and are addressed under the heading of
Spill Prevention, Control and Countermeasures, and Emergency Response.
The identity of chemical additives to drilling fluids and hydraulic fracturing fluids is of
particular concern because these chemicals are used underground where, if appropriate
precautions are not taken, the chemicals could enter underground sources of drinking
water. At the federal level, the Safe Drinking Water Act (SDWA) allows EPA to regulate
the subsurface emplacement of fluid; however, Congress excluded from regulation under
the SDWA the underground injection of fluids (other than diesel fuels) and propping
agents for HVHF. Many gas operators voluntarily disclose the chemicals they use, after
the fact, although some chemicals are not specifically identified because they are claimed
to be trade secrets. The Departments agree that it would be desirable for MDE to review
the chemicals before they are used. The Departments therefore propose the following
standards for chemical disclosure.
The Departments will require the disclosure of all chemicals that the applicant expects to
use on the site, not just chemicals classified as “hazardous chemicals” under the OSHA
Hazard Communication Standard.
The permittee will be required to provide a complete list (Complete List) of chemical
names, CAS22 numbers, and concentrations of every chemical constituent of every
commercial chemical product brought to the site. If a claim is made that the composition
22
A CAS number is a unique number assigned by the Chemical Abstract Service to each chemical entity. If the chemical has not been
assigned a CAS, the permittee shall provide the name of the chemical using the conventions of the International Union of Pure and
Applied Physics. If the constituent is a natural material whose constituents have not been fully characterized, such as walnut shells
used as a proppant, such a description such as “crushed walnut shells” shall be accepted.
32
of a product is a trade secret, the permittee must provide an alternative list (Alternative
List), in any order, of the chemical constituents, including CAS numbers, without linking
the constituent to a specific product. If no claim of trade secret is made, the Complete
List will be considered public information; if a claim is made, the Alternative List will be
considered public information. MDE will retain the list or lists in the permit file. The
Departments will require disclosure of chemicals used on FracFocus, so that the
FracFocus data base can be more nearly complete and useful; however, the Departments
are aware that FracFocus has different requirements, and therefore the posting may be
different.
The operator must provide to the local emergency response agency: a) the Complete List
or Alternative List of all chemical constituents and b) Safety Data Sheets (SDS, formerly
called Material Safety Data Sheets) for all products that contain one or more OSHA
hazardous chemicals.
The operator must provide to the public, upon request, the same information made
available to the local emergency response agency. If the permittee provides the
information to MDE in a format MDE specifies, MDE will post the information on its
website at least until the well completion report is filed, and this will be deemed to satisfy
the operator’s obligation to provide the information to the public.
A person claiming a trade secret must substantiate and attest to the claim, but MDE will
not evaluate whether the claim is legitimate. MDE will keep the information confidential,
but may share it with other State and federal agencies that agree to protect the
confidentiality of the information. A person claiming trade secret must provide the
supplier’s or service company’s contact information, including the name of the company,
an authorized representative, and a telephone number answered 24/7 by a person with the
ability and authority to provide the trade secret information in accordance with the
regulations.
The regulations will require that information furnished under a claim of trade secret be
provided by the person claiming the trade secret to a health professional who states,
orally or in writing, a need for the information to diagnose or treat a patient. The health
professional may share that information with other persons as may be professionally
necessary, including, but not limited to, the patient, other health professionals involved in
the treatment of the patient, the patient's family members if the patient is unconscious,
unable to make medical decisions, or is a minor, the Centers for Disease Control, and
other government public health agencies. Any recipient of the information disclosed
under this regulation shall not use the information for purposes other than the health
needs asserted in the request and shall otherwise maintain the information as confidential.
Information so disclosed to a health professional shall in no way be construed as publicly
available. The holder of the trade secret may request a confidentiality agreement from all
health professionals to whom the information is disclosed as soon as circumstances
permit, but disclosure may not be delayed in order to secure a confidentiality agreement.
Upon written request and statement of need for public health purposes, the person
claiming the trade secret will disclose the chemical identity and percent composition to
any health professional, toxicologist or epidemiologist who is employed in the field of
public health, including such persons employed at academic institutions who conduct
33
public health research. The recipient may share the information as professionally
necessary. Any recipient of the information disclosed under this regulation shall not use
the information for purposes other than the public health needs asserted in the request and
shall otherwise maintain the information as confidential. Information so disclosed to a
health professional, toxicologist or epidemiologist shall in no way be construed as
publicly available. Disclosure may be conditioned on the signing of a confidentiality
agreement before disclosure. Publication of research results without revealing any trade
secret information is not precluded. For example, provided the publication does not
disclose the trade name of the commercial product subject to trade secret protection, or
the identity of the manufacture or distributor of the product, research that utilizes trade
secret information may be published.
Following well completion, the operator shall provide MDE with a list of all chemicals
used in fracturing, the weight of each used, and the concentration of the chemical in the
fracturing fluid. If a claim is made that the weight of each chemical used or the
concentration of each chemical in the fracturing fluid is a trade secret, the operator may
attest to that fact and provide a second list that omits the weight and concentration to the
extent necessary to protect the trade secret. If no claim of trade secret is made, the full
list shall be public information; if a claim of trade secret is made, the list without the
trade secret weight and concentration shall be public information.
E.
Drilling
1.
Use of electricity from the grid
UMCES-AL Report recommendations 2-B, 9-D.-1. (Additional recommendations about
the use of electricity are addressed below in section N., Noise.)
The UMCES-AL Report suggests that Maryland consider mandating electrically-powered
equipment wherever line power is available (or could be made readily available) from the
grid. The Departments agree that this practice would reduce air emissions. The use of
propane or natural gas to power motors and pumps should be encouraged if electricity
from the grid is not available.
There are multiple factors which would favor the use of one power source or fuel over
another, including the land disturbance necessary to bring power to the site, the
greenhouse gas footprint of electricity supplies and the loss of electricity resulting from
electric power transmission. The Departments will require that applicants provide a
power plan that results in the lowest practicable impact from the choice of energy source.
2.
Initiation of drilling
UMCES-AL Report recommendations 5-D.1, 8-I, 9-D.2
The UMCES-AL Report recommended that drilling should avoid times of peak outdoor
recreational periods such as holiday weekends, first day of trout season, and during
sensitive wildlife migratory or mating seasons. In addition, the report recommended that
hours and times of operation be restricted to avoid or minimize conflicts with the public.
The Departments agree that these recommendations would offer a high level of protection
to these activities; however, the Departments acknowledge that once drilling and
fracturing operations have begun, it is generally not safe to halt activities. For this reason,
these restrictions can only be applied to the initiation of a drilling or fracturing operation
34
or other activities that could be planned in advance or temporarily suspended. The
specific restrictions should be included as a condition in the well permit.
3.
Pilot hole
The UMCES-AL Report notes the importance of avoiding drilling through large
underground voids (e.g., caverns, caves, mine workings, abandoned wells) because these
voids increase the risk of losing fluid circulation during drilling and complicate the
cementing process. The principal recommendations for avoiding these dangers involve
setback requirements; in addition the authors suggest that Maryland also consider
mandating the use of surface geophysical techniques (e.g., seismic surveys) or “pilot
hole” boring as part of an exploration/drilling hazard assessment program that is aimed at
identifying other subsurface MSGD hazards that are not well mapped.
The Departments agree that drilling a pilot hole is an excellent way of identifying
geological features, underground voids, gas or fluid bearing formations, and the lowest
fresh water aquifer in the immediate vicinity of the proposed bore hole. One pilot hole
investigation will be required for every pad to investigate the geology and determine all
strata where liquid or gaseous flow occurs. The Departments will also require that the
CGDP include a geological investigation by the applicant of the area covered by the
CGDP. This investigation serves several purposes, including identifying underground
voids. The applicant will be required to submit the survey data in a report to the State. If
the applicant asserts that the geological information is confidential business information,
the State will not release the information to the public for a period of three years.
Where underground mining is suspected to have occurred within 500 feet of the
prospective borehole, based on a review of available records, the applicant shall select, if
possible, drill hole locations that avoid all mine voids and assures lateral support of drill
holes during drilling and casings during well construction. If such locations cannot be
found, voids must be filled or isolated with multiple concentric strings of casing and
cement.
4.
Drilling fluids and cuttings
UMCES-AL Report recommendation 6-G
The UMCES-AL Report notes that high pressure air can be used rather than water as the
“fluid” to bring rock fragments to the surface and cool the drill bit. When subsurface
pressures are high, however, it is necessary to use drilling mud. Drilling mud can use
water or other liquid or gaseous fluids as a base. Water-based drilling mud is a mixture of
water, weighting agents, clay, polymers, surfactants and other chemicals. During
horizontal drilling, mud powers and cools the downhole motor and bit, operates the
navigational tools, provides stability to the borehole, and removes cuttings. The material
returned to the surface is a mixture of drilling mud and native rock. The drilling mud can
be reused. Open pit systems have been used in the past to manage the returned material,
but the UMCES-AL Report recommends that closed-loop drilling systems be required.
The Departments agree.
All intervals drilled prior to reaching the depth 100 feet below the deepest known stratum
bearing fresh water, or the deepest known workable coal, whichever is deeper, shall be
drilled with air, fresh water, a freshwater based drilling fluid, or a combination of the
35
above. Only additives suitable for drilling through potable water supplies can be used
while drilling these intervals. Below the cemented surface casing that isolates the deepest
stratum bearing fresh water, additives other than those suitable for drilling through
potable water can be used if approved by the Department.
A best practice for managing cuttings is to contain the drilling fluid, the returned drilling
fluid and the cuttings in a closed loop system with secondary containment on the well
pad. That means that separating the cuttings from the returned drilling fluid must be done
in tanks or containers, and that any storage of these materials would also have to be in
tanks or containers. The secondary containment could be the zero-discharge well pad
itself or another impermeable containment system, provided the secondary containment is
capable of holding the total volume of the largest storage container or tank located within
the area enclosed by the containment structure.
Due to the potential for cuttings from shale formations to contain Naturally Occurring
Radioactive Material, the UMCES-AL Report recommends that onsite disposal be
prohibited, that the cuttings be tested for radioactivity, and that they be disposed of in a
landfill only if the testing indicates no significant elevation above background levels.
The Departments agree that the cuttings and drilling mud, as well as flowback, produced
water, residue from treatment of flowback and produced water, and any equipment where
scaling or sludge is likely to occur should be tested for radioactivity and disposed of in
accordance with law. The Departments are evaluating whether to impose a limit on the
level of radioactivity in cuttings and drilling mud that may be disposed of in municipal
landfills. The Departments recommend that cuttings and drilling mud also be tested for
other contaminants, including sulfates and salinity, before disposal. If the cuttings show
no elevated levels of radioactivity, and meet other criteria established by MDE, onsite
disposal of the cuttings could be allowed.
5.
Open hole logging
Open hole logging provides important information about the formations encountered and
can be used to optimize the well design and drilling operations. Lithology can be
determined from gamma ray logs, the presence of hydrocarbons by electrical resistivity
logs, liquid-filled porosity by neutron porosity logs and bulk density by density logs.
Borehole caliper logs assist in calculating the amount of cement needed. Mud logging can
be used to determine the concentration of natural gas being brought to the surface with
the drilling mud. The UMCES-AL Report does not make a specific recommendation
about open hole logging, but states that “The best practice would utilize modern openhole well logging methods to help fine tune casing placement and characterize flow and
hydrocarbon zones, [and] perhaps mud logging to determine levels of hydrocarbons in
real-time during drilling….” (UMCES-AL at page 3-11)
Without specifying the methods to be used, current Maryland regulations require the
submission of a well completion report that must include, among other things,
(a) Depth at which any fresh water inflow was encountered;
(b) Lithology of penetrated strata, including color;
(c) Total depth of the well;
36
(d) A record of all commercial and noncommercial oil and gas encountered,
including depths, tests, and measurements;
(e) A record of all salt-water inflows;
(f) Generalized core descriptions, including:
(1) The type and depth of sample;
(2) Indications of oil, water, or gas;
(3) Estimates of porosity and permeability; and
(4) Percent recovery; and
(g) A copy of all electric, radiation, sonic, caliper, directional, and any other type
of logs run in the well.
COMAR 26.19.01.10 V.
To obtain this mandatory data, a driller would have to employ all of the techniques
mentioned above with the exception of caliper logs and mud logging. The caliper logs
would provide information to inform decisions about casing, centralizers, and cement.
For this reason, we recommend that borehole caliper logs be performed.
F.
Casing and Cement
UMCES-AL Report recommendations 3-C, 3-D, 3-E, 7-A.2
1.
Requirements for casing and cement
Before beginning to drill a gas well, the operator must receive approval from MDE of a
plan that describes:
a. how the a stable borehole will be drilled with minimal rugosity;23
b. how complete removal of drilling fluid will be accomplished;
c. how the cement system design addresses challenges to zonal isolation;
d. how other factors that could interfere with the proper placement of the cement
around the casing will be addressed; and
e. how the casing and cement will assure durability throughout the well life cycle.
This plan can be submitted with the permit application, but the permittee must review the
plan in light of information obtained from the pilot hole drilled for that well pad, and
certify to the Department that the plan utilizes the right practices and materials for the
specific situation to assure zonal isolation. Before commencing hydraulic fracturing, the
permittee must certify the sufficiency of the zonal isolation to MDE with supporting data
in the form of well logs, pressure test results, and other appropriate data. Adherence to
the drilling, casing and cementing plan, as well as integrity testing will be a condition of
the permit.
23
Rugosity refers to the roughness of a borehole wall. Rugosity can be observed on caliper logs and image logs Source:
Schlumberger Oil Glossary. High rugosity can make it more difficult to remove the drilling fluid and achieve zonal isolation with
cement.
37
Before drilling below the first casing string, the owner shall either crown the location
around the wellbore to divert fluids, or construct a liquid-tight collar at least three feet in
diameter to prevent surface infiltration of fluids adjacent to the wellbore.
All casing installed in a well shall be steel alloy casing that has been manufactured and
tested consistent with standards established by the American Petroleum Institute (API) in
“5 CT Specification for Casing and Tubing” or ASTM International in “A500/A500M
Standard Specification for Cold-Formed Welded and Seamless Carbon Steel Structural
Tubing in Rounds and Shapes” and have a minimum internal yield pressure rating
designed to withstand at least 1.2 times the maximum pressure to which the casing may
be subjected during drilling, production or stimulation operations.
The minimum internal yield pressure rating shall be based upon engineering calculations
listed in API “TR 5C-3 Technical Report on Equations and Calculations for Casing,
Tubing and Line Pipe used as Casing and Tubing, and Performance Properties Tables for
Casing and Tubing.”
Thread and coupling designs for casing and tubing must meet or exceed the maximum
anticipated tensile, compressive, burst and bending stress conditions for the well. Casing
strings with threads should be assembled to the correct torque specifications to ensure
leak-proof connections.
Operators must use a sufficient number of centralizers to properly center the casing in
each borehole. The cement shall be allowed to set at static balance or under pressure for a
minimum of 12 hours and must have reached a compressive strength of at least 500 psi
before drilling the plug, or initiating any integrity testing
Reconditioned casing may be permanently set in a well only after it has passed a
hydrostatic pressure test with an applied pressure at least 1.2 times the maximum internal
pressure to which the casing may be subjected, based upon known or anticipated
subsurface pressure, or pressure that may be applied during stimulation, whichever is
greater, and assuming no external pressure. The casing shall be marked to verify the test
status. All hydrostatic pressure tests shall be conducted pursuant to API “5 CT
Specification for Casing and Tubing” or other method(s) approved by the Department.
The owner shall provide a copy of the test results to MDE before the casing is installed in
the well.
2.
Isolation
The casing and cement provide zonal isolation between the well and all other subsurface
formations. Liners and tiebacks may be used, provided the exposed casing meets all
regulatory requirements for casing. Surface casing shall be run and permanently
cemented from the surface to a depth at least 100 feet below the deepest known stratum
bearing fresh water, or the deepest known workable coal, whichever is deeper.
Intermediate casing, if used, must isolate all fluid bearing zones through which it passes.
Production casing must be cemented along the horizontal portion of the well bore and to
at least 500 feet above the highest formation where hydraulic fracturing will be
performed, or 500 feet above the uppermost fluid bearing formation not already isolated
by surface casing or intermediate casing, whichever is shallower. In this way, casing and
cement will isolate all fluid-bearing (gas and liquid) formations through which the
38
borehole passes before reaching the target formation, but it will be possible to monitor
annular pressure, which provides the operator with valuable information.
3.
Cased-hole logging, Integrity testing and Pressure testing
Cased-hole logging occurs after the casing is cemented. The objectives are to determine
the exact location of the casing, the casing collars, and the integrity of the cement job.
Common methods of assessing the integrity of the cemented casing are cement bond
logging and gamma ray logging. According to the UMCES-AL Report, newer testing
equipment can perform a segmented radial cement bond logging (SRCBL), which can
determine the presence and locations of small channels in the cement that could indicate
poor zonal isolation.
The UMCES-AL Report recommended Maryland should consider amending its
regulations to require SRCBL (or equivalent casing integrity testing) and other types of
logging ( i.e., neutron logging) as part of a cased-hole program. The Departments agree.
SRCBL will be required for all casing strings from the surface casing and below along
the portions that are cemented. This can be supplemented by other methods, including
omnidirectional cement bond logging and observations and measurements during
cementing.
An applicant for a drilling permit will be required to provide a plan for integrity and
pressure testing for approval by MDE. If there is evidence of inadequate casing integrity
or cement integrity, the Department must be notified and remedial action proposed.
Integrity testing must be performed periodically during the lifetime of the well. The
specific types of tests and the frequency of testing will be addressed in each permit.
Integrity testing will be required when a well is re-fractured. All integrity test results
must be reported to MDE.
G.
Blowout Prevention
UMCES-A: Report recommendation 3-F
A blowout preventer is a mechanical device that can close or seal a wellbore if pressure
in the well cannot be contained. Without a blowout preventer, extreme erratic pressures
and uncontrolled flow encountered during drilling could cause a blowout -- the
uncontrolled release of liquid and gas from the well and the ejection of casing, tools and
drilling equipment from the well. The blowout preventer is installed at the top of the
surface casing. Depending on the design, a blowout preventer may close over an open
wellbore, seal around tubular components, or shear through the casing to seal the well.
The UMCES-AL Report recommended that Maryland require the use of blowout
prevention equipment with two or more redundant mechanisms. The Departments agree
and will make this a requirement. Existing COMAR regulations already require the
blowout prevention equipment must be tested to a pressure in excess of that which may
be expected at the production casing point before drilling the plug on the surface casing;
and penetrating the target formation. The Departments will require that blow out
preventers must be tested at a pressure at least 1.2 times the highest pressure normally
experienced during the life of the blow out preventer. If this highest pressure occurs
during well stimulation, it must be tested at a pressure at least 1.2 times higher than that
39
experienced during well stimulation. The blow out preventer must be tested on a weekly
basis.
H.
Hydraulic Fracturing
UMCES-AL Report recommendation 3-G
The UMCES-AL Report recommended that hydraulic fracturing should avoid times of
peak outdoor recreational periods such as holiday weekends, first day of trout season, and
during sensitive wildlife migratory or mating seasons.
The Departments accept the proposed limitation on hydraulic fracturing; however, the
State realizes that it is unsafe to halt some operations before they are concluded. Except
for activities that can be temporarily suspended, avoidance of these times must therefore
be considered when operations are planned. In addition, if a well pad is not located in a
place likely to adversely impact the peak outdoor recreational activities, this limitation
will not apply.
The UMCES-AL Report recommended that tiltmeter or microseismic surveys be done to
characterize the Marcellus shale across the region. The Departments will require that a
tiltmeter or microseismic survey shall be performed by the permittee for the first well
hydraulically fractured on each pad to provide information on the extent, geometry and
location of fracturing. The permittee shall provide this information to MDE.
Diesel fuel shall not be used in hydraulic fracturing fluids. The Departments encourage
companies to adopt innovative technology for well development that does not require
large amounts of water or chemicals if the technology becomes practical. In all cases,
companies should use additives with the least toxicity available.
I.
Flowback and Produced Water
This topic is further discussed under Wastewater Treatment and Disposal, below.
Flowback and produced water shall be handled in a closed loop system of tanks and
containers at the pad site. Flowback and produced water may not be stored in surface
impoundments or ponds.
J.
Air Emissions
UMCES-AL Report recommendations 2-B
On August 16, 2012, EPA published a final rule in the Federal Register establishing New
Source Performance Standards (NSPS) and National Emission Standards for Hazardous
Air Pollutants (NESHAPs) for the oil and gas sector. EPA’s final rule includes the first
federal air standards for natural gas wells that are hydraulically fractured, along with
requirements for several other sources of pollution in the oil and gas industry that had not
previously been regulated at the federal level. These include requirements to reduce
VOCs and air toxics from new and modified compressors, pneumatic controllers, storage
vessels at gathering and boosting stations, and glycol dehydrators. EPA is allowing a
phased approach to comply with new requirements because of comments indicating that
sufficient equipment would not be available by the proposed effective date. By January 1,
2015, however, all sources must conduct green completions.
40
The Departments propose to require that new facilities in Maryland meet these federal
standards upon startup. In addition, the Departments recommend additional measures for
reducing air emission.
1.
Green Completion or Reduced Emissions Completion
Green completion shall be achieved on all gas wells drilled in Maryland. In green
completions, gas and hydrocarbon liquids are physically separated from other fluids and
delivered directly into equipment that holds or transports the hydrocarbons for productive
use. Reduced Emissions Completions shall be required for re-fracturing.
Flaring shall be allowed only if the content of flammable gas is very low, or when flaring
is required for safety. The following circumstances shall not justify flaring:
a. Inadequate water disposal capacity
b. Undersized flowback equipment
c. Except for wells drilled pursuant to a bifurcated permit24 for exploration
only, lack of a pipeline connection
2.
Flaring
When flaring is permitted during well completion, re-completions or workovers25 of any
well, operators must adhere to the following requirements:
a. Operators must either use raised/elevated flares or an engineered
combustion device with a reliable continuous ignition source, which have
at least a 98 percent destruction efficiency of methane. No pit flaring is
permitted.
b. Flaring may not be used for more than 30-days on any exploratory or
extension wells (for the life of the well), including initial or recompletion
production tests, unless operation requires an extension.
c. Flares shall be designed for and operated with no visible emissions, except
for periods not to exceed a total of five minutes during any two
consecutive hours.
3.
Electricity from the grid
Refer to Section VI.-E.1 on the use of electricity to support drilling operations.
4.
Engines
a. All on-road and non-road vehicles and equipment using diesel fuel must
use Ultra-Low Sulfur Diesel fuel (maximum sulfur content of 15 ppm).
b. All on-road vehicles and equipment must limit unnecessary idling to 5
minutes.
c. All trucks used to transport fresh water or flowback or produced water
must meet EPA Heavy Duty Engine Standards for 2004 to 2006 engine
24
A bifurcated permit can be issued under Md. Env. Code, § 14-106 when the drilling will be conducted in geologic formations not
yet proven to be productive. Because the Marcellus shale formation has been demonstrated to be productive, bifurcated permits shall
not be issued for drilling in the Marcellus shale in Maryland. Exploratory wells in the Marcellus shale will require a permit under Md.
Env. Code, § 14-104.
25
Workovers include the repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the
production of hydrocarbons; the term includes refracturing.
41
model years, which include a combined NOx and NMHC (non-methane
hydrocarbon) emission standard of 2.5 g/bhp-hr.
d. Except for engines necessarily kept in ready reserve, a diesel nonroad
engine may not idle for more than 5 consecutive minutes. (A ready-reserve
state means an engine may not be performing work at all times, but must
be ready to take over powering all or part of an operation at any time to
ensure safe operation of a process.)
5.
Storage tanks
EPA recently updated the 2012 standards for storage tanks. 78 Fed. Reg. 58416
(September 23, 2013). The Departments propose to require that all new natural gas
operations in Maryland meet these standards upon startup.
6.
Top-down BAT
The Department of the Environment intends to require top-down Best Available
Technology (BAT) for the control of air emissions. This means that the applicant will be
required to consider all available technology and implement BAT control technologies
unless it can demonstrate that those control technologies are not feasible, are costprohibitive or will not meaningfully reduce emissions from that component or piece of
equipment. BAT emissions control technology will be mandatory for workovers. MDE
will analyze top-down BAT demonstrations from applicants and approve the applicants
BAT determination before a permit is issued. This builds on the EPA STAR program,
and therefore a separate requirement to participate in this voluntary EPA program is not
needed. MDE will also require a rigorous leak detection and repair program.
MDE is considering whether it is feasible to require permittees to estimate the remaining
methane emissions and offset them with greenhouse gas credits. If this occurs, the
permittees will have to estimate and report emissions to the State annually
K.
Waste and Wastewater Treatment and Disposal
UMCES-AL Report recommendations 4-J, 4-K
Wastes produced at well sites include cuttings, spent drilling muds, and other solid
wastes. After a well is hydraulically fractured, some portion of the hydraulic fracturing
fluid, called flowback, moves up the wellbore to the surface. Other water that is produced
from the well after the initial flowback is termed produced water. These are the major
types of wastewater generated at a drill site. Wastewater associated with shale gas
extraction can contain high levels of total dissolved solids (TDS), fracturing fluid
additives, metals, and naturally occurring radioactive materials. Typically, flowback
contains significant concentrations of dissolved sodium, calcium, chloride, barium,
magnesium, strontium, and potassium. It can also contain volatile organic compounds.
There are a few options for managing this wastewater:
1. Underground injection in regulated Class II injection wells
2. Pretreatment, followed by further treatment by a sewage treatment plant
3. Evaporation/crystallization
4. Recycling.
42
Operators have been moving toward recycling of gas development wastewaters, and
reusing them for hydraulic fracturing. This is the most environmentally sound method,
and the UMCES-AL Report recommends that Maryland establish a goal of 100 percent
recycling, with a preference for onsite recycling rather than shipment to a central
treatment plant. The Departments recommend that, unless the permittee can demonstrate
that it is not practicable, the permittee be required to recycle not less than 90 percent of
the flowback and produced water and carry out that recycling on the pad site where the
waste was generated.
The UMCES-AL Report also recommends that Maryland should not allow the discharge
of any untreated or partially-treated brine, or residuals from brine treatment facilities, into
surface waters. The Departments agree, but note that MDE has taken appropriate steps to
prevent such discharge. To understand this situation, it is necessary to explain the
regulation of direct and indirect discharges of pollutants.
Direct and indirect discharges of pollutants to navigable waters are regulated under the
Clean Water Act through the National Pollutant Discharge Elimination System (NPDES)
permit program. Authority for issuing permits in Maryland has been delegated to MDE.
Currently, federal regulations mandate that “there shall be no discharge of waste water
pollutants into navigable waters from any source associated with production, field
exploration, drilling, well completion, or well treatment (i.e., produced water, drilling
muds, drill cuttings, and produced sand).” 40 CFR 435.32. Thus, the direct discharge of
flowback or other brine is already prohibited.
Indirect discharge means the introduction of pollutants from a non-domestic source into a
publicly owned wastewater treatment system, often called a Publicly Owned Treatment
Works (POTW). Indirect discharges to POTWs are subject to General Pretreatment
Regulations, which provide that a user of a POTW may not introduce into a POTW any
pollutant(s) that cause a POTW to violate its own discharge limitations or that disrupt the
POTW, its treatment processes or operations, or the processing, use or disposal of its
sludge, and thereby cause the POTW to violate its permit.26 There are, however, no
national standards specifically for the indirect discharge of gas exploration and
development wastewaters. As a result, some shale gas wastewater has been transported to
POTWs that are not equipped to treat this wastewater. Where POTWs discharged the
inadequately treated wastewater to fresh water streams, the salts in the brine entered the
streams, where they could kill or damage the aquatic organisms. Where discharges of
treated brine were upstream of drinking water intakes, they impacted drinking water by
contributing to high levels of disinfection by-products.
EPA has committed to develop standards to ensure that wastewaters from gas extraction
receive proper treatment and can be properly handled by POTWs. EPA plans to propose a
rule for shale gas wastewater in 2014. Until these regulations are in place, MDE has
requested that POTWs not accept these wastewaters without prior consultation with
MDE. MDE does not intend to authorize any POTW facility that discharges to fresh
water to accept these wastewaters.
26
These and other pretreatment general prohibitions that are designed to protect the POTW from damage and its workers from harm
can be found at 40 CFR 403.5.
43
With regard to disposal in Class II injection wells, the UMCES-AL Report noted that
establishing UIC Class II injection wells in Maryland would avoid long distance trucking
of produced waters; however, it also noted that locations in Maryland suitable for siting
injection wells may be very limited. The Departments agree that it is not likely that Class
II wells will be located in Maryland and therefore defers any consideration of the matter
unless and until someone proposes to apply for a permit for a Class II injection well.
In order to assure that all wastes and wastewater are properly treated or disposed of, the
Departments propose to require permittees to keep a record of the volumes of wastes and
wastewater generated on-site, the amount treated or recycled on-site, and a record of each
shipment off-site. The records may take the form of a log, invoice, manifest, bill of lading
or other shipping documents. For shipments off-site, the record would have to include the
following information:
1. The type of waste
2. The volume or weight of waste
3. The identity of the hauler
4. The name and address of the facility to which the waste was sent
5. The date of the shipment
6. Confirmation that the full shipment arrived at the facility
The records would be maintained by the permittee for at least three years, and MDE
could audit them during site inspections or otherwise. The requirements would be
included as a condition of the permit.
L.
Leak Detection
UMCES-AL Report recommendation 2-A
The Departments accept the proposed recommendations (summarized below) and include
additional comments.
A methane leak detection and repair plan that conforms to EPA’s Natural Gas STAR
Program guidelines and EPA’s best practice guidelines for leakage detection and repair
programs must be submitted to MDE for approval with the application for a well permit.
It must address leak detection and repair from wellhead to transmission line and assure
prompt repair of leaks. Records of leak detection and repair shall be made available to
MDE upon request.
A statement must be submitted listing all equipment available for the detection,
prevention, and containment of gas leaks and oil spills. COMAR 26.19.01.06C(17).
MDE may not issue a drilling and operating permit if drilling or operations would result
in physical and preventable loss of oil and gas. COMAR 26.19.01.09J.
On site air pollution monitoring, discussed in the monitoring section, shall be included as
an element of the leak detection program.
M. Light
UMCES-AL Report recommendations 5-E, 5-E.1, 8-G, 8-H
44
The UMCES-AL Report recommends that night lighting be used only when necessary,
directed downward, and use low pressure sodium light sources wherever possible. If drill
pads are located within 1,000 feet of aquatic habitat, screens or restrictions on the hours
of operation may be required to reduce light pollution further. The Departments accept
the proposed recommendations for lighting at drill pad sites with the following
modifications.
Light restrictions and management protocols must also minimize conflicts with
recreational activities, in addition to minimizing stress and disturbance to sensitive
aquatic and terrestrial communities.
The Departments agree that restrictions on hours of operation could reduce light
pollution, but recognize that many activities are carried on continuously once they begin.
Downward directed low pressure sodium light sources and screens might be required for
such operations.
N.
Noise
UMCES-AL Report recommendation 5-D, 9-B, 9-D, 9-D.3, 9-D.4, 9-D.5
The UMCES-AL Report recommends that each of the counties in western Maryland
should revisit noise regulations and enforcement policies and confirm they are
appropriate for this industrial activity. Additionally, the report recommends that noise be
reduced by: requiring electric motors (in place of diesel-powered equipment) for any
operations within 3,000 ft. of any occupied building; encouraging the use of electric
motors in place of diesel-powered equipment for operations not within 3,000 ft. of an
occupied building; restricting hours and times of operation to avoid or minimize
conflicts; require a measurement of ambient noise levels prior to operation; the
construction of artificial sound barriers where natural noise attenuation would be
inadequate; and requiring all motors and engines to be equipped with appropriate
mufflers.
The Departments agree that noise must be controlled, and that compliance with the
existing noise regulations should be sufficient. The Departments recommend that the
applicant for a permit submit a plan for complying with the noise standards and for
verifying compliance after operations begin. The Departments will incorporate the
concept of “noise sensitive locations” into its review of the CGDP. Site-specific noise
provisions can be incorporated into individual permits.
Pursuant to State law, MDE has adopted environmental noise standards. A local
government may adopt its own noise control ordinance, rules or regulations, provided
they are not less stringent than those the State adopts. Enforcement of the environmental
noise standards, whether State or local, is the responsibility of the local government.
Noise limits apply at the boundary of: (1) a property; or (2) a land use category, as
determined by the responsible political subdivision. Md. Env. Code, Title 3. The
measurement of noise levels shall be conducted at points on or within the property line of
the receiving property or the boundary of a zoning district27, and may be conducted at any
“Zoning district” means a general land use category, defined according to local subdivision, the activities and uses for which are
generally uniform throughout the subdivision. For the purposes of this regulation, property which is not zoned “industrial”,
“commercial”, or “residential” shall be classified according to use as follows: (a) “Industrial” means property used for manufacturing
27
45
point for the determination of identity in multiple source situations. COMAR
26.02.03.02D(2). The general standards for Environmental Noise are:
Table VI-1
Maximum Allowable Noise Levels (dBA)
for Receiving Land Use Categories
Day/Night28 Industrial
Commercial
Residential
Day
75
67
65
Night
75
62
55
Special rules apply to construction and demolition sites: a person may not cause or permit
noise levels emanating from construction or demolition site activities which exceed: (a)
90 dBA during daytime hours; (b) The levels specified in the table above during
nighttime hours. COMAR 26.02.03.02B. The noise regulations also address vibrations:
“A person may not cause or permit, beyond the property line of a source, vibration of
sufficient intensity to cause another person to be aware of the vibration by such direct
means as sensation of touch or visual observation of moving objects. The observer shall
be located at or within the property line of the receiving property when vibration
determinations are made.” Id.
Methods for minimizing noise impacts resulting from drilling and fracturing operations
include: (1) careful siting of facilities—distance, direction, timing, and topography are
the primary considerations in mitigating noise impacts; (2) placement of walls, artificial
sound barriers, or evergreen buffers between sources and receptors (e.g., around well
pads and compressor stations); (3) use of noise reducing equipment (e.g., mufflers) on
flares, drill rig engines, compressor motors, and other equipment; and (4) use of electric
motors in place of diesel-powered equipment. In the event noise sensitive locations or
sensitive species are identified in the Environmental Assessment, these additional
measures may be necessary to protect against adverse impacts.
Currently, county government bears the responsibility for monitoring and enforcing noise
regulations. However, many counties do not have the capacity or the equipment to
monitor. For this reason, the Departments may require the permittee to hire an
independent contractor to conduct periodic noise monitoring and additional noise
monitoring in response to a complaint.
O.
Invasive species
UMCES-AL Report recommendations 5-G, 5-G.1, 5-H, 6-H, 6-H.1, 6-H.2, 6-I
and storing goods; (b) “Commercial” means property used for buying and selling goods and services; (c) “Residential” means property
used for dwellings. COMAR 26.02.03.01
28
“Daytime hours” means 7 a.m. to 10 p.m., local time. “Nighttime hours” means 10 p.m. to 7 a.m., local time. COMAR 26.02.03.01
46
The UMCES-AL recommended that the permittee submit an invasive species plan that
emphasizes early detection and rapid response and meets certain criteria. The
Departments agree.
The applicant must submit a plan with every well application for preventing the
introduction of invasive species (plants and animals) and controlling any invasive that is
introduced. The invasive species management plan should emphasize avoidance, early
detection and rapid response. Invasive species monitoring will be required at the
appropriate times of the year to identify early infestations. The plan must include, at a
minimum:
1. flora and fauna inventory surveys of sites prior to operations, including water
withdrawal sites;
2. procedures for avoiding the transfer of species by clothing, boots, vehicles; and
water transfers including assuring that the water withdrawal equipment is free
from invasive species before use and before it is removed from the withdrawal
site;
3. interim reclamation following construction and drilling to reduce opportunities for
invasion;
4. annual monitoring and treatment of new invasive species populations as long as
the well is active; and
5. post-activity restoration to pre-treatment community structure and composition
using seed that is certified free of noxious weeds.
P. Spill Prevention, Control and Countermeasures and Emergency
Response
UMCES-AL Report recommendations 4-H, 5-B.1, 5-B.2, 7-B, 7-B.1, 7-B.2, 7-B.3
The UMCES-AL Report recommends that permit applicants should be required to
develop site-specific emergency response plans, taking into account that the optimum
response may differ depending on the season of the year and the topography of the site.
Further, the report recommends that the plan must also include a list of all chemicals or
additives used, expected wastes generated by hydraulic fracturing, approximate quantities
of each material, the method of storage on-site, Material Safety Data Sheets for each
substance, toxicological data, and waste chemical properties. The Departments agree that
each permittee must prepare a site-specific emergency response plan and that the
permittee must provide a list of chemicals and corresponding Safety Data Sheets to first
responders before beginning operations; however, the Departments do not agree that all
the detailed information described above needs to be in the plan or submitted to MDE
with the permit application.
Spill Prevention, Control and Countermeasures Plans (SPCC Plans) are intended to
prevent any discharge of oil. Spill cleanup and emergency response plans are intended to
address spills or other releases after they occur. The Departments identify as a best
practice that facilities develop plans for preventing the spills of oil and hazardous
substances, using drip pans and secondary containment structures to contain spills,
conducting periodic inspections, using signs and labels, having appropriate personal
47
protective equipment and appropriate spill response equipment at the facility, training
employees and contractors, and establishing a communications plan. In addition, the
operator shall identify specially trained and equipped personnel who could respond to a
well blowout, fire, or other incident that personnel at the site cannot manage. These
specially trained and equipped personnel must be capable of arriving at the site within 24
hours of the incident.
The federal Hazard Communication Program regulations, sometimes called Worker Right
to Know, require that the chemical manufacturer, distributor or importer provide SDS for
each hazardous chemical to downstream users as a way of communicating information on
the hazards. Employers must ensure that SDSs are readily accessible to employees for all
hazardous chemicals in their workplace.
Under revised regulations, the SDS must be presented in a consistent 16 section format.
Sections 1 through 8 contain general information about the identity of the chemical,
hazards, composition and ingredients, first aid measures, fire-fighting measures, response
to releases, handling and storage, and measures to minimize worker exposure. Sections 9
through 11 contain other technical and scientific information, such as physical and
chemical properties, stability and reactivity information and toxicological information.
Sections 12 through 15 contain ecological information, disposal considerations, transport
information, and regulatory information. Section 16 must include the date the SDS was
prepared or last revised and it may contain other useful information. Where the preparer
is unable to find any applicable information, it must be stated on the SDS.
The Departments believe that the SDSs and the other requirements for emergency
response are sufficient to enable first responders and well pad staff to appropriately
respond to emergencies involving chemicals. In Section VI-D, we require operators to
provide a list of chemicals on site and SDSs to the local emergency response agency.
Operators shall, prior to commencement of drilling, develop and implement an
emergency response plan, establish a way of informing local water companies promptly
in the event of spills or releases, and work with the governing body of the local
jurisdiction in which the well is located to verify that local responders have appropriate
equipment and training to respond to an emergency at a well.
Q.
Site Security
UMCES-AL Report recommendations 7-C, 7-C.1. 7-C.2. 7-C.3, 10-F
The UMCES-AL Report recommends perimeter fencing, giving local emergency
responders duplicate keys to locks, posting appropriate signage, and using security guards
to control access. The Departments accept the proposed site security recommendations as
best practices; however the decision whether to use security guards should be made by
the permittee on a site-specific basis.
R.
Closure and Reclamation both Interim and Final
UMCES-AL Report recommendation 1-K, 5-H, 10-E
The goal of reclamation is to return the developed area to native vegetation (or predisturbance vegetation in the case of agricultural land returning to production) and restore
the original hydrologic conditions to the maximum extent possible. The UMCES-AL
48
Report recommended two-stage reclamation: (1) interim reclamation following
construction and drilling to stabilize the ground and reduce opportunities for invasive
species and (2) post-activity restoration using species native to the geographic range and
seed that is certified free of noxious weeds.
The Departments agree.
Reclamation shall address all disturbed land, including the pad, access roads, ponds,
pipelines and locations of ancillary equipment. Pre-development and post-development
photographic documentation will be required to ensure site closure conditions are
satisfied.
As recommended by UMCES-AL, topsoil should be stockpiled during site development
activities, covered during storage, redistributed back onto agricultural land as part of the
land reclamation process. Soil compaction should be avoided at all times.
49
SECTION VII – MONITORING, RECORDKEEPING AND REPORTING
UMCES-AL Report recommendations 1-A, 1-B, 2-A, 2-C, 2-D, 2-E, 3-G, 4-C, 5.G-1, 7A.3
The Departments accept the proposed monitoring, recordkeeping and reporting
recommendations with the following modifications, additions and comments.
A. DNR emphasizes that a minimum of 2 years of pre-development baseline data is
necessary to evaluate the condition and characteristics of aquatic resources,
particularly the living resources, since statewide monitoring experience
demonstrates there is great variability on a seasonal and annual basis.
Characterization and baseline monitoring data will be important to identify
whether any impacts to the resources have occurred as a result of drilling
activities, and can be used as basis for mitigating damage.
B. State agencies will develop standard protocols for baseline and environmental
assessment monitoring, recordkeeping and reporting. In addition, the State
agencies will develop standards for monitoring during operations at the site,
including drilling, hydraulic fracturing, and production.
C. All information collected at the site and within the study area must be reported
according to the State developed guidelines. This is to include monitoring and
assessment data for air and water quality, terrestrial and aquatic living resources,
invasive species, well logs, other geophysical assessments, such shale fracturing
characteristics and additional information as required by the State.
D. State agencies will require more extensive testing of surface water and ground
water parameters both randomly and in instances where elevated levels have been
detected.
E. Cuttings, flowback, produced water, residue from treatment of flowback and
produced water, and any equipment where scaling or sludge is likely to occur
shall be tested for radioactivity and disposed of in accordance with law.
F. Personnel and time needed for inspections and compliance activities cannot be
determined until we have final regulations and have a sense of the pace and scope
of drilling. Nevertheless, the Department can assess fees adequate to cover the
expenses of the program, including inspections.
The Environment Article of the Maryland Code provides in pertinent part:
§ 14-105. Drilling well and disposing of well's products -- Application for permit
b) Fees. -- The Department shall establish and collect fees for:
(1) The issuance of a permit to drill a well under § 14-104 of this subtitle;
(2) The renewal of a permit to drill a well under § 14-104 of this subtitle;
and
50
(3) The production of oil and gas wells installed after October 1, 2010.
(c) Fees -- Rate. -- The fees imposed under subsection (b) of this section
shall be set by the Department at the rate necessary to implement the
purposes set forth in § 14-123 of this subtitle.
§ 14-123. Use of money
The Department shall use money in the Fund solely to administer and
implement programs to oversee the drilling, development, production, and
storage of oil and gas wells, and other requirements related to the drilling
of oil and gas wells, including all costs incurred by the State to:
(1) Review, inspect, and evaluate monitoring data, applications, licenses,
permits, analyses, and reports;
(2) Perform and oversee assessments, investigations, and research;
(3) Conduct permitting, inspection, and compliance activities; and
(4) Develop, adopt, and implement regulations, programs, or initiatives
to address risks to public safety, human health, and the environment
related to the drilling and development of oil and gas wells, including the
method of hydrofracturing.
MDE will consider all of the costs to be incurred by the State in connection with its gas
well program and propose an appropriate fee schedule by regulation.
51
SECTION VIII – MISCELLANEOUS RECOMMENDATIONS
A.
Zoning
UMCES-AL Report recommendation 1-M
The UMCES-AL Report recommended that both counties amend their zoning ordinances
to spell out in which zoning districts MSGD would be permitted. Zoning is an excellent
way to separate incompatible land uses; however, authority to enact zoning rests with the
local jurisdictions. Zoning has been controversial, especially in Garrett County. It is a
local matter over which the Departments have no control.
B.
Financial assurance
UMCES-AL Report recommendations 1-N, 3-H
This recommendation has been satisfied with the 2013 legislative passage of SB854,
sponsored by Senator George Edwards, providing financial assurance for gas and oil
drilling.
C.
Forced Pooling
UMCES-AL Report recommendation 1-D
The Departments offer the following comments regarding the forced pooling
recommendation.
Consideration of this recommendation is premature. Once the requirements of the
Executive Order have been fulfilled, this recommendation could receive additional
consideration which would require further study, legal analysis and considerable
governmental and public review.
52
SECTION IX – MODIFICATIONS TO PERMITTING PROCEDURES
The Departments are persuaded that the recommended best practices for permit
procedures can be implemented through regulatory changes and policy without additional
statutory authority. If natural gas extraction by high volume hydraulic fracturing is
allowed in Maryland, more detailed procedures for the processing of the Comprehensive
Gas Development Plan (CGDP) will have to be developed. The time schedule for
processing the CGDP set forth in Section III will be followed.
53
SECTION X – IMPLEMENTING THE RECOMMENDATIONS
The Maryland General Assembly has authorized the Maryland Department of the
Environment to regulate oil and gas wells. With a few notable exceptions, the statutory
language is general and MDE is authorized to promulgate rules and regulations and to
place in permits conditions it deems reasonable and appropriate to assure that the
operations are carried out in compliance with the law and provide for public safety and
the protection of the State’s natural resources. Md. Env. Code Ann., §§ 14-103 and
14-110. This model allows the Department to apply expertise, exercise judgment and
adapt to change.
The Department’s regulations on oil and gas wells have not been revised since 1993 and
thus were written before recent advances in technology and without the benefit of more
recent research. Our current regulations for oil and gas wells are not appropriate for high
volume hydraulic fracturing. Even though MDE could implement many of the
recommendations in individual permits, the inconsistencies between the existing
regulations and the recommendations would certainly cause confusion and could prompt
lawsuits or permit challenges if natural gas extraction by high volume hydraulic
fracturing is allowed in Maryland in the future. The CGDP would be difficult to
implement without additional regulations. For these reasons, the regulations should be
revised to reflect the recommendations. This is a lengthy process, with opportunities for
review by the legislature and public participation.
54
APPENDIX A – MEMBERS OF THE COMMISSION
Chair
David A. Vanko, Ph.D., geologist and Dean of The Jess and Mildred Fisher College of
Science and Mathematics at Towson University
Commissioners
George C. Edwards, State Senator, District 1
Heather Mizeur, State Delegate, District 20
James M. Raley, Garrett County Commissioner
William R. Valentine, Allegany County Commissioner
Peggy Jamison, Mayor of Oakland
Shawn Bender, division manager at the Beitzel Corporation and president of the Garrett
County Farm Bureau
Ann Bristow, Ph.D., board member, Savage River Watershed Association*
Stephen M. Bunker, director of Conservation Programs, Maryland Office of the Nature
Conservancy
Jeffrey Kupfer, Esq., senior advisor, Chevron Government Affairs
Clifford S. Mitchell, M.D., director, Environmental Health Bureau, DHMH
Dominick E. Murray, secretary of the Maryland Department of Business and Economic
Development
Paul Roberts, Garrett County resident and co-owner of Deep Creek Cellars winery
Nicholas Weber, Ph.D., chair of the Mid-Atlantic Council of Trout Unlimited
Harry Weiss, Esq., partner at Ballard Spahr LLP
*
Dr. Bristow was appointed to the Commission in late 2013 to replace
John Fritts, Ph.D., who resigned.
A-1
APPENDIX B – COMMENTS OF THE ADVISORY COMMISSION
The purpose of the Marcellus Shale Safe Drilling Initiative is to assist State policymakers
and regulators in determining whether and how gas production from the Marcellus Shale
can be carried out in Maryland without the risk of unacceptably and negatively impacting
public health, safety, the environment and natural resources. The Departments of Natural
Resources and the Environment are to consult with the Advisory Commission during the
Departments’ investigations and production of the three reports called for in Executive
Order 01.01.2011.11. The Advisory Commission plays a valuable role by representing
diverse points of view, making suggestions to the Departments, and providing
constructive criticism of the Departments’ work and decisions. The Advisory
Commission conducts its affairs openly and transparently and actively seeks and
considers public comments, which are received through the Advisory Commission’s web
site and at Commission meetings.
Advisory Commission members include representatives from local and State government,
the gas industry, environmental organizations, businesses, private citizens and
landowners, a public health professional, a geology professor, and an environmental
lawyer. The members have different perspectives and opinions, as well as a range of
expertise and, consequently, achieving unanimity on all the issues discussed is difficult.
From its inception, members of the Advisory Commission have agreed that if shale gas
production is to proceed in Maryland, it needs to be done “right.” Although the definition
of “right” may vary to some extent among the Commissioners, all agree that safety is of
paramount importance.
A key practice is the requirement of a Comprehensive Gas Development Plan (CGDP).
Some Commissioners identified this as an excellent idea and the most important of the
recommendations. Although most Commissioners supported the concept, several
expressed serious concerns about it. These included:
o By favoring multi-well pads and avoiding sensitive areas, the CGDP will
concentrate the adverse impact of gas development in a few places to the
detriment of those who live there;
o The CGDP adds an onerous and cumbersome layer of review and approval
without significant benefit; and
o There are practical problems to implementing a CGDP, including the time needed
to implement to plan and the ability to complete an exploratory well and adjust
the plan.
This Appendix summarizes the positions of the members of the Advisory Commission on
the best practices in this report. It reflects the opinions of individual Commissioners as of
June 13, 2014, regarding the suitability of the State’s proposed best practices for use in
B-1
the ongoing risk assessment study. All Commissioners reserve the right to change their
opinions as more information becomes available, and as ongoing studies are completed.
Changes in Commissioner viewpoints will be reflected in the third report.
At the June 13, 2014, Marcellus Shale Advisory Commission meeting, Commissioners
were asked to respond, for each proposed best practice, to this question:
Given my current understanding of the facts and the science, I think
1. it is an appropriate standard to carry forward to the risk assessment.
2. it may not be the appropriate standard to carry forward to the risk assessment,
but I can live with it.
3. it is not an appropriate standard to carry forward to the risk assessment
because [fill in the blank].
The statement was qualified by “given my current understanding of the facts and the
science” in recognition that new information will continue to become available as more
research is conducted and published.
For every best practice, the majority of Commissioners voting agreed either that the best
practice was an appropriate standard to carry forward to the risk assessment or, even
though they were not sure it was the appropriate standard, they were comfortable with
allowing it to proceed to the risk assessment. When Commissioners did not think the
practice was an appropriate standard, they had an opportunity to provide a reason. By
way of example, these included:
o the standard is not a best practice because it has not been shown to be superior to
the approach commonly employed;
o there is a lack of science supporting the practice;
o there is insufficient knowledge about the groundwater aquifers and flow systems
in western Maryland;
o there is too little data on health effects, air quality and noise impacts;
o the setback is too long
o the setback is not long enough; and
o the practice is insufficiently described to make a judgment.
Additional detail is provided in portions of the minutes of the June 13 meeting. The votes
are tallied in the following chart:
Section III.
Response
1
2
3
Comprehensive Gas Development Plan (CGDP) for landscape level planning
Commissioners
Bunker, Edwards, Jamison, Mitchell, Raley, Vanko, Weiss
Kupfer
 Bristow: Will provide written comment, approach not shown to be
B-2


superior to the approach commonly employed; there is no research on
the effects of CGDP on public health and there is concern that this
practice may intensify potential impacts.
Roberts: Not appropriate, no science to support it; there is no research
on the effects of CGDP on public health and there is concern that this
practice may intensify potential impacts.
Weber: Endorse approach for protecting natural resources, the CGDP
incompletely deals with human and safety concerns and how they will
be addressed
Section V. Individual well permit following CGDP approval
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer, Raley, Vanko, Weiss
2
3
 Bristow:
 Mitchell: Needs to have DHMH and other agencies as commenting
agencies on permit review
 Roberts: Same as Mitchell
 Weber: Lack of specific API references, same as Mitchell
The Departments agreed to amend the practice to include notification of all
landowners within a 2,500 ft radius.
Section IV. Location restrictions and setbacks
1,000 ft setback from well to property boundary
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer, Raley, Vanko, Weiss
2
Mitchell
3
 Bristow: Needs to be the Limit of Disturbance (LOD), not the borehole
 Roberts: Lack of supporting science
 Weber: Lack of supporting science, no accounting of groundwater flow
upstream or downstream from the well
Section IV. Location restrictions and setbacks
2,000 ft vertical setback between lowest freshwater zone and target formation
Response Commissioners
1
Edwards, Jamison, Raley, Weber
2
Bunker, Kupfer, Mitchell, Weiss, Vanko
3
 Bristow: Lack of supporting science and knowledge of aquifer
 Roberts: Same as Bristow
Section IV. Location restrictions and setbacks
450 ft setback from aquatic habitat to edge of pad
Response Commissioners
1
Bunker, Edwards, Jamison, Mitchell, Raley, Vanko
2
Kupfer, Weiss
B-3
3


Bristow: Need implementation of Wolman report recommendations,
groundwater contamination via casing failure could directly impact
aquatic habitat, 450 ft not protective enough, concerned about
agricultural land
Roberts: Same as Bristow
Section IV. Location restrictions and setbacks
600 ft setback from special conservation areas to edge of pad
Response Commissioners
1
Edwards, Jamison, Mitchell, Raley, Vanko
2
Bunker, Kupfer, Weber, Weiss
3
 Bristow: Need health data/studies on air quality impacts
 Roberts: Same as Bristow, shocking the state would limit offset to 600 ft
from an “Irreplaceable Natural Areas”
Section IV. Location restrictions and setbacks
300 ft setback from special conservation areas to edge of pad
Response Commissioners
1
Edwards, Jamison
2
Bunker, Kupfer, Raley, Vanko, Weiss
3
 Bristow: Need health data/studies on air quality and noise impacts
 Mitchell: Would like to evaluate noise data
 Roberts: Same as Bristow, not enough distance to reduce noise and air
impacts
 Weber: Same as Roberts
Section IV. Location restrictions and setbacks
750 ft setback from downdip side of limestone outcrops to borehole
Response Commissioners
1
Bunker, Edwards, Jamison, Mitchell, Raley, Weiss, Vanko
2
Kupfer, Weber
3
 Bristow: Don’t see the reason to reduce the setback, not enough
information
 Roberts: Not enough distance, not properly evaluated
Section IV. Location restrictions and setbacks
Eliminate absolute 1,000 ft setback from coal mines in lieu of pilot hole and geologic
investigations to develop site specific drilling, casing and cementing techniques
Response Commissioners
1
Bunker, Jamison, Kupfer, Mitchell, Raley, Weiss, Vanko
2
Bristow, Edwards, Roberts, Weber
3
B-4
Section IV. Location restrictions and setbacks
1,320 ft setback from historic gas wells to borehole, including laterals
Response Commissioners
1
Edwards, Jamison, Mitchell, Raley, Weiss, Vanko
2
Bunker, Kupfer
3
 Bristow: Not enough data
 Roberts: Not enough data
 Weber: Not enough data
Section IV. Location restrictions and setbacks
1,000 ft setback from compressor stations to any occupied building
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer
2
Mitchell, Raley, Weber, Weiss, Vanko
3
 Bristow: No health data/studies
 Roberts: No health data/studies
Section IV. Location restrictions and setbacks
1,000 ft setback from edge of drill pad disturbance to any occupied building
Response Commissioners
1
Bunker, Vanko
2
Edwards, Jamison, Kupfer, Mitchell, Raley, Weiss
3
 Bristow: No data/studies on how animals and agricultural use are
affected by direct impacts and byproducts
 Roberts: Same as Bristow
 Weber: Same as Bristow
Section IV. Location restrictions and setbacks
2,000 ft (or reduced with study and consent to minimum of 1,000 ft) setback from a
private drinking water well to the well pad
Response Commissioners
1
Bunker, Edwards, Jamison, Raley, Vanko, Weiss
2
Mitchell
3
 Bristow: Recommend 1 kilometer setback, no science to support a
lesser setback, use the Vengosh study results
 Kupfer: Setback is too wide and is unsubstantiated by existing
information. Private wells have not been mapped out with setbacks
applied in the constraint analysis.
 Roberts: Same as Bristow
 Weber: Same as Bristow
Note: The risk analysis will run scenarios on 3 setback distances of 1,000 ft, 2,000 ft and
1 kilometer.
B-5
Section IV. Location restrictions and setbacks
1,000 ft setback from a wellhead protection area or a source water assessment area for a
public ground water system to the well pad
Response Commissioners
1
Bunker, Jamison, Mitchell, Raley, Vanko, Weber
2
Bristow, Edwards, Kupfer, Roberts, Weiss
3
Section IV. Location restrictions and setbacks
1,000 ft setback from a source water assessment area for a public surface water intake
system
Response Commissioners
1
Mitchell, Raley, Vanko
2
Bristow, Bunker, Edwards, Jamison, Kupfer, Roberts, Weber ,Weiss
3
Section IV. Location restrictions and setbacks
A well pad cannot be located within the watersheds of the following public drinking
water reservoirs: Broadford Lake, Piney Reservoir, Savage Reservoir
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Vanko, Weber, Weiss
2
3
Section VI. Engineering, Design and Environmental Controls and Standards
A. Site construction and sediment and erosion control plans
Response Commissioners
1
Bunker, Edwards, Jamison, Weiss, Vanko
2
Bristow, Kupfer, Mitchell, Roberts
3
Weber: Insufficient information on best practices – wants more detail
Note: No vote recorded for Raley
Section VI. Engineering, Design and Environmental Controls and Standards
B. Transportation planning
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer, Raley, Vanko
2
Bristow, Mitchell, Weber, Weiss
3
Roberts
Section VI.
C. Water
Response
1
2
Engineering, Design and Environmental Controls and Standards
Commissioners
Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Vanko, Weiss
Bristow, Roberts , Weber
B-6
3
Section VI. Engineering, Design and Environmental Controls and Standards
D. Chemical disclosure
Response Commissioners
1
2
Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Vanko, Weiss
3
 Bristow: Grossly inappropriate
 Roberts: Extremely complicated issue, not enough time to research the
issue, don’t fully understand the details
 Weber: Same as Roberts, concerned about depleted uranium used in
perforation devices
Section VI. Engineering, Design and Environmental Controls and Standards
E. Drilling
Response Commissioners
1
Edwards, Raley, Bunker, Jamison, Mitchell, Vanko
2
Bristow, Kupfer, Roberts, Weber
3
Note: No vote recorded from Weiss
Section VI. Engineering, Design and Environmental Controls and Standards
F. Casing and cement
Response Commissioners
1
Edwards, Jamison, Weiss
2
Bunker, Kupfer, Mitchell, Raley, Vanko
3
 Weber: Lack of science and understanding
 Roberts: Same as Weber
 Bristow: Same as Weber, would like to see a cost assessment of
enforcement needs by MDE
Section VI. Engineering, Design and Environmental Controls and Standards
G. Blowout prevention
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
Section VI. Engineering, Design and Environmental Controls and Standards
H. Hydraulic fracturing
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weiss, Vanko
2
Weber
B-7
3
Section VI. Engineering, Design and Environmental Controls and Standards
I. Flowback and produced water
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
Section VI. Engineering, Design and Environmental Controls and Standards
J. Air emissions
Response Commissioners
1
Bunker, Edwards, Kupfer, Mitchell, Raley, Vanko
2
Jamison, Weiss
3
 Roberts: This is an area of evolving research, can’t support at this time
 Weber: Same as Roberts
 Bristow: Same as Roberts
Section VI. Engineering, Design and Environmental Controls and Standards
K. Waste and wastewater treatment and disposal
Response Commissioners
1
Edwards, Kupfer, , Weiss Vanko
2
Bunker, Jamison, Mitchell, Raley
3
 Roberts: State should review and revise regulations on what constitutes
on site storage (length of time, type of material, etc) so that this practice
is not a de facto option for disposal and doesn’t result in a prolonged
period of time allowable for on site storage
 Weber: Same as Roberts
 Bristow: GPS tracking should be publicly available, recognize that
shipping of waste exacerbates the problem of waste disposal, there are
Environmental Justice concerns about exporting our wastes to another
state
Section VI. Engineering, Design and Environmental Controls and Standards
L. Leak detection
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
B-8
Section VI. Engineering, Design and Environmental Controls and Standards
M. Light
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
Section VI.
N. Noise
Response
1
2
3
Engineering, Design and Environmental Controls and Standards
Commissioners
Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Weber, Weiss, Vanko
Bristow, Roberts
Section VI. Engineering, Design and Environmental Controls and Standards
O. Invasive species
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Weiss, Vanko
2
Bristow, Roberts, Weber
3
Section VI. Engineering, Design and Environmental Controls and Standards
P. Spill prevention, control and countermeasures and emergency response
Response Commissioners
1
Bunker, Edwards, Jamison, Kupfer, Mitchell, Roberts, Weiss, Vanko
2
Raley, Weber
3
Bristow: Need to address financial and capacity needs for emergency
response
Section VI. Engineering, Design and Environmental Controls and Standards
Q. Site security
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
Section VI. Engineering, Design and Environmental Controls and Standards
R. Closure and reclamation
Response Commissioners
1
Bristow, Bunker, Edwards, Jamison, Kupfer, Mitchell, Raley, Roberts,
Weber, Weiss, Vanko
2
3
B-9
Section VII.
Response
1
2
3
Monitoring, Recordkeeping and Reporting
Commissioners
Bunker, Edwards, Mitchell, Raley,
Jamison, Kupfer, Roberts, Vanko, Weiss
 Weber: Needs more detail on the practices
 Bristow: Same as Weber, monitoring information should be made
publicly available
B-10
APPENDIX C – RESPONSE TO PUBLIC COMMENTS
Contents
AIR EMISSIONS ..................................................................................................... 3
ANCILLARY INFRASTRUCTURE ...................................................................... 9
CHEMICALS......................................................................................................... 12
THE COMPREHENSIVE GAS DEVELOPMENT PLAN .................................. 15
CONTAMINATION OF DRINKING WATER ................................................... 28
ENVIRONMENTAL ASSESSMENT AND ENVIRONMENTAL IMPACT
STATEMENTS ...................................................................................................... 36
EARTHQUAKES .................................................................................................. 40
EMERGENCY RESPONSE .................................................................................. 41
ENFORCEMENT AND INSPECTIONS .............................................................. 45
ENGINEERING, DESIGN AND ENVIRONMENTAL CONTROLS AND
STANDARDS ........................................................................................................ 57
FORCED POOLING ............................................................................................. 67
IMPACTS ON CHESAPEAKE BAY ................................................................... 67
INDIVIDUAL WELL PERMIT ............................................................................ 69
LEGISLATION ..................................................................................................... 70
NOISE .................................................................................................................... 73
PRE-DEVELOPMENT BASELINE DATA ......................................................... 76
PROCESS .............................................................................................................. 77
CLASSIFICATION OF WASTES UNDER THE RESOURCE
CONSERVATION AND RECOVERY ACT (RCRA). ........................................ 81
RISK ASSESSMENTS .......................................................................................... 84
SPREAD OF FRACTURES .................................................................................. 85
STORMWATER MANAGEMENT ...................................................................... 95
STRINGENCY OF THE PROPOSED BEST PRACTICES ................................ 97
SURFACE IMPACTS AND SETBACKS .......................................................... 105
C-1
TRUCK TRAFFIC ............................................................................................... 129
WASTE DISPOSAL ............................................................................................ 133
WATER USE ....................................................................................................... 138
WELL CASING AND CEMENT ....................................................................... 144
C-2
AIR EMISSIONS
1. The greenhouse gas benefits of natural gas are overstated.
a. I ask that the State also re-consider its statement in the Overview (Sec. II)
that natural gas produces lower GHG emissions than coal when burned for
electricity. Any comparisons of the two energy sources should analyze the
complete “life-cycle” of production. Calculation of the GHG footprint of
shale gas development should include documentation of leakage rates
(rates of higher than 3 percent effectively cancel out gas’s GHG
advantages over coal use) and a full accounting of potential emissions
from all truck traffic needed for extraction and waste disposal. If Maryland
requires a closed-loop system for waste disposal, and then transport of the
waste to other states, it is likely that the truck transport needs here (and the
resulting diesel emissions) will be greater than average.
b. A recent study published in the Proceedings of the National Academy of
Sciences found that the methane leakage rate would have to be kept below
1 percent in order to ensure that natural gas has an immediate climate
benefit over all other fossil fuels. [Alvarez, Ramon A., Stephen W. Pacala,
James J. Winebrake, William L. Chameides, and Steven P. Hamburg.
"Greater Focus Needed on Methane Leakage from Natural Gas
Infrastructure." Proceedings of the National Academy of Sciences
(2012): n. pag. Web.]
The statement in the draft report: “When burned to generate electricity, natural gas
produces lower greenhouse gas emissions than oil and coal....” was intended to
address only the burning of the fuel to generate electricity, and did not consider the
life-cycle of the process. The Departments acknowledge that leakage of methane
could reduce or even negate the advantage of burning natural gas, and MDE is
proposing measures to reduce the emissions of methane to the maximum extent
practicable.
2. Companies should be required to reduce, report, and offset methane emissions.
a. The study should include a section dedicated to best practices for reducing
methane emissions at every stage of the natural gas system.
b. In order to achieve real “best practices” the state should require drilling
permittees to meet the maximum emissions abatement potential based on
technologies that exist today, to be achieved through a combination of
offsets and EPA-certified prevention measures.
c. Permittees should be required to work with EPA STAR Program staff to
estimate their annual greenhouse gas emissions after the adoption of costeffective abatement control measures, and include that estimate in their
permit application. In order to ensure that natural gas production and
processing does not contribute to climate change, permittees should then
include a plan for investing in carbon offsets to offset their estimated
annual leakage.
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d. Fugitive emissions from oil and gas operations are a source of direct and
indirect greenhouse gas emissions. The Revised 1996 IPCC Guidelines for
National Greenhouse Gas Inventories (IPCC Guidelines) provide a threetier approach for assessing fugitive emissions from oil and gas activities.
These approaches range from the use of simple production-based emission
factors and high level production statistics (i.e., Tier-1) to the use of
rigorous estimation techniques involving highly disaggregated activity and
data sources (i.e., Tier-3), and could include measurement and monitoring
programs. There is no mention of use of Tier 3 monitoring program to
ensure proper controls are in place.
e. Gas companies should be required to meet a zero percent leakage rate for
methane throughout the fracking process. To the extent leakage cannot be
reduced to zero, the releases should be offset.
f. The release of methane has been a great danger to people and animals, and
methane is a potent greenhouse gas. The BMPs should require gas
companies to meet a 1 or 2 percent leakage rate for methane throughout
the drilling process. Leakage should be monitored by a certifiable method
and reported annually.
g. In order to account for methane leakage that will occur after shale gas
enters the transmission line, MDE should consider requiring permittees to
offset leakage at a ratio greater than 1:1.
The Department of the Environment intends to require top-down Best Available
Technology (BAT) for the control of methane emissions. This means that the
applicant will be required to consider all available technology and implement BAT
control technologies unless it can demonstrate that those control technologies are not
feasible, are cost-prohibitive or will not meaningfully reduce emissions from that
component or piece of equipment. MDE will analyze top-down BAT demonstrations
from applicants and approve the applicants BAT determination before a permit is
issued. This builds on the EPA STAR program, and therefore a separate requirement
to participate in this voluntary EPA program is not needed. MDE will also require a
rigorous leak detection and repair program.
MDE is considering whether it is feasible to require permittees to estimate the
remaining methane emissions and offset them with greenhouse gas credits. If this
occurs, the permittees will have to estimate and report emissions to the State
annually. Under EPA’s Greenhouse Gas Reporting Program, an onshore natural gas
production29 facility that emits 25,000 metric tons of carbon dioxide equivalents
(CO2e) or more per year must report its greenhouse gas emissions annually to EPA.
29
Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad
(including but not limited to compressors, generators, dehydrators, storage vessels, and portable non-self-propelled equipment which
includes well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non-transportationrelated equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization,
separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or
measurement vessels and all enhanced oil recovery operations using CO2 or natural gas injection, and all petroleum and natural gas
production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial
island. 40 CFR § 98.230.
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Requiring production facilities to offset methane emissions at greater than a 1:1 ratio
to account for methane leakage that occurs after the gas enters the transmission line
would add to the cost of natural gas without reducing leakage in downstream
infrastructure, such as transmission lines, because these are separately owned and
operated.
3. Venting and flaring
a. Venting should be absolutely prohibited.
b. The proposed BMPs allow flaring for up to 30 days for exploratory wells
and place some limits on flaring during drilling. This BMP is too vague
and all flaring should be prohibited. Flaring for periods longer than several
days under any circumstances will result in an unacceptable level of noise
and light and possibly dangerous air quality for nearby residents,
especially those with small children or respiratory conditions.
c. The report says that flares should have no visible emissions. How can
flared emissions NOT be visible?
Vented emissions are releases to the atmosphere by design or operational practice.
Use of BAT for emissions control will reduce the venting of emissions, as will the
requirement for Reduced Emissions Completion. Flares are a critical piece of safety
equipment at natural gas sites to ensure that combustible gases do not accumulate
and cause an unsafe condition. The goal is to use the flare as little as possible, but a
flare or other combustion device should be available in case of an upset.
The light of a flare would make it visible, but the concept of “no visible emissions”
refers to the opacity or “smokiness” of the exhaust from a flame, not light. If a flare
is operating properly, there should be little or no unburned fuel to appear as smoke
and the combustion products will be mostly carbon dioxide and water.
4. Diesel Generators / Electricity from the Grid
a. Where possible, electricity from electrical transmission lines should be
used to minimize air and noise pollution; natural gas and or solar should
be used for all on-site electrical generation where feasible.
b. Maryland should prohibit diesel generators, and take a stronger stance on
prohibiting internal combustion engines for compressors and the like.
As stated in the draft report, there are multiple factors which would favor the use of
one power source or fuel over another, including the land disturbance necessary to
bring power to the site, the greenhouse gas footprint of electricity supplies and the
loss of power resulting from running electrical transmission lines to the drill site. The
Departments therefore proposed to require applicants to provide a power plan that
results in the lowest practicable impact from the choice of energy source.
EPA has promulgated air quality regulations for stationary engines which differ
according to whether: 1) the engine is new or existed before the regulations took
effect; 2) the engine is located at an area source or a major source; and 3) the engine
is a compression ignition or a spark ignition engine. These regulations include
National Emission Standards for Hazardous Air Pollutants (NESHAP)40 CFR Part
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63, Subpart ZZZZ (“the RICE rule”), New Source Performance Standards (NSPS) for
Stationary Spark Ignition Internal Combustion Engines 40 CFR Part 60, Subpart
JJJJ and NSPS 40 CFR Part 60, Subpart IIII.
Under EPA regulations, however, stationary source rules do not apply to motor
vehicles, or to non-road engines, which are: 1) self-propelled (tractors, bulldozers);
2) propelled while performing their function (lawnmowers); or 3) portable or
transportable (has wheels, skids, carrying handles, dolly, trailer or platform). Note:
a portable non-road engine becomes stationary if it stays in one location for more
than 12 months (or full annual operating period of a seasonal source).
The Department of the Environment is investigating the feasibility (legal and
technical) of regulating non-road engines at Marcellus Shale drilling sites.
5. Health Issues
a. Evaporation and crystallization when combined with other chemicals
which may be used/mixed on-site at gas-wells cause ground-level ozone
which have serious health consequences on people, animals and plants.
b. Compression stations create toxic air that has been linked to illness.
c. Unsafe levels of specific emissions and radiation should be prohibited.
d. A study done by The Colorado School of Health found air pollution
caused by hydraulic fracturing may contribute to “acute and chronic health
problems for those living near natural gas drilling sites."
(http://attheforefront.ucdenver.edu/?p=2546&utm_source=feedburner&ut
m_medium=feed&utm_campaign=Feed%3A+theforefront+%28%40theFo
refront%29).
e. The state should consider that toxic air pollutants also pose a threat in
determining setbacks. One peer-reviewed study found high levels of
endocrine-disrupting chemicals in the air during the drilling phase. From
the study: “Selected polycyclic aromatic hydrocarbons (PAHs) were at
concentrations greater than those at which prenatally exposed children in
urban studies had lower developmental and IQ scores.”
http://www.endocrinedisruption.com/chemicals.air.php
Ground level or "bad" ozone is not emitted directly into the air, but is created by
chemical reactions between oxides of nitrogen (NOx) and volatile organic compounds
(VOC) in the presence of sunlight. Emissions from industrial facilities and electric
utilities, motor vehicle exhaust, gasoline vapors, and chemical solvents are some of
the major sources of NOx and VOC, and are precursors to ground level ozone. The
State is proposing to require that best available technology be used to control
emissions from well pad operations.
To the extent Maryland is not preempted by regulations of the Federal Energy
Regulatory Commission, Maryland will enforce a minimum setback distance of 1,000
feet between a compressor station and an occupied building. Data from recent air
monitoring studies of well controlled Marcellus operations using the most sensitive
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monitoring techniques show concentrations well below health effects levels at 1000
feet.
MDE is considering requiring applicants – in certain situations where drilling is
close to communities -- to demonstrate compliance with State air toxics regulations COMAR 26.11.15. The basic requirements for demonstrating air toxics compliance
is to estimate emissions; use State-provided screening models or other modeling to
estimate concentrations off of the property; and show that offsite concentrations of
toxic air pollutants are below health protective benchmarks established in the
regulations.
6. Reduced Emissions Completions/Green Completions
a. The Draft is lacking in the required use of ‘Reduced Emissions
Completions’ industry practice.
b. The proposed Maryland BMP provision for green completions at wellhead
is an important and achievable provision that will greatly contribute to
reducing GHG footprint of gas production activities in the state.
Requiring green completions will provide important near-term reductions
in GHG associated with gas development in Maryland.
c. State regulations should require green completions for fracking, refracking
and workovers, and also incorporate reporting requirements for green
completions, gas bleed limits for pneumatic controllers, reduction
requirements from storage vessels at the well site, and air toxic
requirements from glycol dehydrators used at the well site.
The draft best practices report mandated the use of Reduced Emissions Completions
for all wells but did not explicitly say that it should also be required for re-fracturing.
It will be. A workover is the process of performing major maintenance or remedial
treatments on a gas well. BAT emissions control technology will be mandatory.
7. Detecting and Repairing Leaks and Fugitive Emissions
a. Gas companies should be required to implement the model leakage
detection and repair (LDAR) program rules as described in EPA’s “Leak
Detection and Repair: A Best Practices Guide.” In order to avoid the
preventable loss of gas during the transmission and storage and
distribution phases, the methane LDAR recommendations should be
expanded to include transmission and distribution pipelines, pipeline
compressor stations, and storage facilities.
b. The BMPs recommend that a methane leak detection and repair (LDAR)
program must be established from wellhead to transmission line. This is a
strong recommendation and it is vital that it is implemented strongly.
Maryland’s leak detection and repair BMP should be strengthened by
requiring that the programs conform to EPA’s Natural Gas STAR Program
guidelines and EPA’s best practice guidelines for leakage detection and
repair programs, the elements of which include:
i. Written LDAR Program
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ii. Training
iii. LDAR Audits
iv. Contractor Accountability
v. Internal Leak Definition for Valves and Pumps
vi. More Frequent Monitoring
vii. Repairing Leaking Components
viii. Delay of Repair Compliance Assurance
ix. Electronic Monitoring and Storage of LDAR Data
x. QA/QC of LDAR Data
xi. Calibration/Calibration Drift Assessment
xii. Records Maintenance
c. We urge an approach that leads to a leak prevention planning requirement
and a process of continuous improvement.
The Departments agree that a strong LDAR program is essential and will require
each permittee to develop and implement a plan to detect and repair leaks from the
wellhead to the transmission line that meets EPA’s guidelines. MDE’s authority,
however, does not extend to the transmission lines. MDE will provide detailed
guidance for the LDAR program, including guidance on detection methods,
frequency of inspections, repair and recordkeeping. A gas well permit is renewed
every five years during the life of the well, and this provides an opportunity for
improving the guidance and requiring a revised LDAR plan.
8. Recommended Emission Controls
a. The minimum state standards should require that permittees adopt these
ten technologies and practices.
i. Green Completions to capture oil and gas well emissions.
ii. Plunger Lift Systems or other well deliquification methods to
mitigate gas well emissions.
iii. Tri-Ethylene Glycol (TEG) Dehydrator Emission Controls to
capture emissions from dehydrators.
iv. Desiccant Dehydrators to capture emissions from dehydrators
(when the gas flow rate is less than 5 MMcfd and have temperature
and pressure limitations).
v. Dry Seal Systems to reduce emissions from centrifugal compressor
seals.
vi. Improved Compressor Maintenance to reduce emissions from
reciprocating compressors.
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vii. Low-Bleed or No-Bleed Pneumatic Controllers used to reduce
emissions from control devices.
viii. Pipeline Maintenance and Repair to reduce emissions from
pipelines.
ix. Vapor Recovery Units used to reduce emissions from storage
tanks.
x.
Leak Monitoring and Repair to control fugitive emissions from
valves, flanges, seals, connections and other equipment.
b. We urge that all of the EPA New Source Performance standards be
included and most importantly they be made mandatory.
Requiring top-down BAT emissions control technology will require that the operator
implement BAT control technologies unless it can demonstrate that those control
technologies are not feasible, are cost-prohibitive or will not meaningfully reduce
emissions from that component or piece of equipment, making it unnecessary to list
the specifically requested technologies and practices.
Applicable EPA New Source Performance Standards are mandatory requirements.
9. The March 2013 CSSD standards appear to be particularly stringent in the area of
air pollution. For instance, their performance standard #10 quantifies “green
completion” by calling for a methane “destruction efficiency” of 98 percent. Their
performance standard #11 specifies what percentage of drill rig engines should
comply with EPA Tier 4 emission standards by what year.
The Maryland best practices recommendations are consistent with CSSD
performance standard #10. Maryland is probably preempted from making
performance standard #11 a requirement because section 209 of the Clean Air Act
precludes it. CSSD and its members are, of course, free to voluntarily accelerate
compliance dates.
ANCILLARY INFRASTRUCTURE
1. Gathering lines
a. Standards for the location, materials, construction or testing of gathering
lines must be addressed before permitting is approved in the State of
Maryland.
b. The absence of specific BPs for gathering lines, gas processing units,
compressor stations, or aquifer hydrological considerations are
unacceptable.
c. The Maryland Public Service Commission should adopt standards for the
location, materials, construction or testing of these lines before MDE
approves CGDP plans or issues permits
d. Significantly stronger and more hazardous volatile components in
unconventional production, compared to standard output in past decades
accelerate pipeline corrosion as well.
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e. The report notes that the Maryland Public Service Commission (PSC)
regulates intrastate gas and liquid pipelines, and that it appears that the
PSC has not established any standards for the location, materials,
construction, or testing of gathering lines. API has a published
recommended practice, RP 80, “Guidelines for the Definition of Onshore
Gas Gathering Lines” that the PSC and others may find of value.
The federal Pipeline and Hazardous Materials Safety Administration (PHMSA),
regulates interstate gathering lines and the PSC regulates intrastate gathering lines
for pipeline safety. PHMSA has set standards for the design, installation,
construction, and initial testing and inspection of gathering lines that apply to
intrastate gathering lines as well as interstate gathering lines. If the lines are
metallic, corrosion protection is required. The location of intrastate gathering lines
is not under the control of either PHMSA or the PSC. The locations of gathering
lines will be addressed in the CGDP.
The PHMSA is in the process of collecting new information about gathering pipelines
in an effort to better understand the risks they may now pose to people and the
environment. If the data indicate a need, PHMSA may establish new safety
requirements for large-diameter, high-pressure gas gathering lines in rural locations.
Pending this action, the Departments are recommending two simple and
commonsense requirements: that the locations of the lines be registered through
Miss Utility, and that all pipelines and fittings be designed for at least the greatest
anticipated operating pressure or the maximum regulated relief pressure in
accordance with the current recognized design practices of the industry.
The determination of whether a pipeline is a gathering line can be complicated, and
both API RP 80 and the PHMSA webpage have helpful information.
2. Compressor station planning is omitted and should be inserted with “pipeline
planning” in the planning principles.
Page 10 of the draft BP report includes the planning principle “adhere to
Departmental siting policies (to be developed) to guide pipeline planning and direct
where hydraulic directional drilling and additional specific best management
practices are necessary for protecting sensitive aquatic resources when streams must
be crossed.” This principle applies to linear facilities, like pipelines. Compressor
stations are covered under the CGDP. On page 9 of the draft BP report in the
Application Criteria and Scope section it states: “Companies intending to develop
natural gas resources are required to submit a CGDP for the area where the
applicant may conduct gas exploration or production activities and install supporting
infrastructure (compressor stations, waste water treatment facilities, roads, pipelines,
etc.) for a period of at least five years.”
3. UMCES-AL recommends that applicants wishing to drill wells be required to
notify property owners residing within the established setback that an application
has been filed for development. This notification requirement should also apply to
citing of compressor stations and other ancillary equipment. (As outlined in Title
20 of the Md. Code, Public Service Commission Article) [The commenter
presumably means COMAR Title 20] Applicants who wish to construct ancillary
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infrastructure are required to notify all landowners whose property line falls
within the current required setback (1,000 feet.)
The Departments have been unable to locate a recommendation by UMCES-AL to
notify property owners “residing within the established setback area.” The
Departments adopted UMCES-AL recommendation 4-B, that the applicant be
required to notify the owners of any drinking water well within 2,500 feet of the
vertical borehole that an application has been filed. Current regulations require the
applicant for a well permit to certify that the applicant has notified, in writing, each
landowner and leaseholder of real property that borders the proposed drillable lease
area of the applicant's intention to file an application for a permit to drill a well. The
Departments would retain this requirement and add the notification of owners of
drinking water wells within 2,500 feet.
The locations of ancillary facilities, including compressors, will be reviewed in the
CGDP. The Departments will consider requiring that applicants for approval of a
CGDP also notify each landowner and leaseholder of real property that borders the
proposed drillable lease area and any other location where ancillary infrastructure
will be located. There will be opportunities for public participation in the CGDP
review process.
4. Should include the statement, “Any further plans to modify the engineering or
capacity to exceed the designed limits will not be allowed without a plan for a
complete upgrade of the pipeline to newer expected maximum pressures.”
Pipelines should not be operated above design limits. If new regulations for pipelines
are adopted, the regulations generally specify whether they apply to existing
pipelines.
5. Comment: This statement from the draft report is incorrect: “In the past, gathering
lines were generally small diameter and did not operate under high pressure.
PHMSA has recognized that lines being put into service in shale plays like the
Marcellus are generally of much larger diameter and operating at higher pressure
than traditional rural gas gathering lines, increasing the concern for safety of the
environment and people near operations.” The rural gathering lines from the
Accident Dome underground storage wells are under very high pressure when gas
is being injected into the wells during warm months and extracted during the
winter months.
The statement was adapted from this sentence in a PHMSA FAQ on gathering lines:
“The lines being put into service in the various shale plays like Marcellus, Utica,
Barnett and Bakken are generally of much larger diameter and operating at higher
pressure than traditional rural gas gathering lines, increasing the concern for safety
of the environment and people near operations.” It is not clear whether the pipelines
connected to the Accident Dome underground storage wells would be classified as
gathering lines or transmission lines. In any event, the statement is qualified by the
word “generally.”
6. There is a need to ensure proper regulation of rural compressor stations that may
not be regulated by the federal government.
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Rural compressor stations that are part of interstate pipelines are regulated by
PHMSA and FERC. The locations of compressor stations on gathering lines and
intrastate pipelines will be addressed in the CGDP. Compressors, if large enough,
also require air permits from MDE.
CHEMICALS
1. The State should prohibit the injection of any toxic chemical into the earth.
Almost all substances, including water and minerals essential to human health, are
toxic at some dose. The best practices recommendation was that the applicant would
disclose the identity of each chemical to be used in drilling and fracturing, including
trade secret chemicals, to MDE. Only approved chemicals could be used. The best
practices will be revised to provide that the maximum amount of a chemical expected
to be used, as well as the identity of the chemical, must be provided to MDE with the
permit application.
Wastewater can be disposed of in deep injection wells. Class II wells inject fluids
associated with oil and natural gas production. There are no Class II wells in
Maryland, and it is unlikely that any could be established because the geology is not
suitable. If deep well injection is found to be feasible in Maryland in the future, the
public will have opportunity to participate in the permitting process. EPA has
established regulations for Class II wells that are designed to protect drinking water.
2. Information about toxicological profiles and epidemiological evaluations,
exposure risks, protective equipment and protective measures for every chemical
used should be provided to MDE, DHMH, workers on site, persons living
adjacent to the site, health professionals, and emergency responders.
The recommended best practices address the need for having information on
hazardous chemicals available and provided to MDE, emergency responders, health
professionals and the public. This will be accomplished by requiring the applicant
for a drilling permit to submit Safety Data Sheets (SDS) to MDE and the local
emergency response agency for every hazardous chemical that is expected to be on
site at any stage of the operation. MDE will consider posting all of the SDSs on its
website as a way of making the information available to persons living adjacent to the
site and the public generally.
The required content of the SDS includes:
o Identification
o Hazard(s) identification
o Composition/information on ingredients
o First-aid measures
o Fire-fighting measures
o Accidental release measures
o Handling and storage
o Exposure controls/personal protection
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o Physical and chemical properties
o Stability and reactivity
o Toxicological information
3. A company should have to fully disclose the identity of all chemicals to be used
in advance of their use.
The proposed best practice was to require disclosure of all OSHA hazardous
chemicals. The Departments have reconsidered and will require the disclosure of all
chemicals that the applicant expects to use on the site.
4. Disclosure should not be limited to OSHA “hazardous chemicals.”
The Departments agree and have altered the best practice.
5. After the well has been drilled and hydraulically fractured, a company should
have to disclose the identity and amount of every chemical used. The information
should be posted for each well on a publicly accessible and searchable website.
Disclosure of chemicals on FracFocus is not sufficient, but it should be
mandatory.
The permittee would be required to provide a complete list of chemical names, CAS
numbers, and concentrations of every chemical constituent used in HVHF. If a claim
is made that the composition of a product is a trade secret, the permittee must provide
a list, in any order, of the chemical constituents, including CAS numbers, without
linking the constituent to a specific product. This list will be posted on MDE’s
website. The Departments will revise the best practice to require disclosure on
FracFocus, so that the FracFocus data base can be more nearly complete and useful.
6. The State should require the use of unique tracer chemicals in hydraulic fracturing
fluids that would allow identification of the source of any contamination.
Currently, radioisotopes, nano iron, and DNA fragments are being examined as
potential tracers. Although each approach has limitations and a timeline for
effectiveness, they may be useful in detecting leaks and failures or accidents in
the future.
Research is ongoing to identify potential tracers and evaluate their usefulness. In the
future, the Departments will consider whether to require the addition of tracers to
fracturing fluid.
7. If the companies refuse to list their proprietary chemicals then the State should
mandate tracers to track the migration of and source of contaminants.
The proposed best practices would require companies to disclose proprietary
chemicals or refrain from using them in Maryland.
8. Long-term monitoring of surface water and groundwater should be mandated for
the tracer chemical and other constituents of fracking fluid. Groundwater moves
very slowly.
The State agencies will develop standards for monitoring during operations at the
site, including production.
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9. Trade Secret issues
a. The State should not recognize any claim of trade secret.
b. If the State recognizes trade secrets, there should be a presumption against
the claim of trade secrecy and the burden should be on the claimant to
prove the claim by clear and convincing evidence. The State should
develop an administrative mechanism by which any citizen can challenge
a claim of trade secrecy.
c. The State should provide a way for health professionals to access trade
secret information simply and immediately.
d. The use of confidentiality or non-disclosure agreements should be
prohibited.
A trade secret is a kind of intellectual property and is protected by the Constitution.
In addition, trade secrets and other confidential commercial information are
protected by State statutes. The Departments are not free to make an exception for
one type of trade secret. However, the best practices report recommended a process
whereby the burden would be on the claimant to substantiate the claim. Even if the
claim is valid, the applicant will have to disclose the identity of the trade secret
chemicals to MDE. A process exists under the Public Information Act to challenge
the withholding of a document on the grounds of trade secrecy.
The best practices also recommended rules for disclosure to health professionals
similar to the rules applicable under the OSHA Hazard Communication Standard
(HCS). According to the Maryland Occupational Health Division, the HSC has been
used in Maryland without significant difficulties. Upon further consideration of
comments, however, the Departments are revising the recommendation concerning
disclosure to health professionals to reduce the burden on the health professionals to
obtain the information and to allow the health professional to communicate the
information to the patient and other health professionals. Disclosure to health
professionals is not limited to those treating individuals; it can also be made
available to epidemiologists and others with legitimate need. The best practices will
be clarified on this point.
Confidentiality or non-disclosure agreements are necessary to protect legitimate
trade secrets.
10. Fracking fluids should be tested before and after injection to establish toxicity and
evaluate potential harm.
The potential harm of fracking fluids can be evaluated based on the chemical content,
which will be disclosed to MDE with the application for a permit. As noted in the
draft best practices report: “Wastewater associated with shale gas extraction can
contain high levels of total dissolved solids (TDS), fracturing fluid additives, metals,
and naturally occurring radioactive materials. Typically, flow back contains
significant concentrations of dissolved sodium, calcium, chloride, barium,
magnesium, strontium, and potassium. It can also contain volatile organic
compounds.” Cuttings, flowback, residue from treatment of flowback and produced
water, and any equipment where scaling or sludge is likely to occur shall be tested for
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radioactivity and disposed of in accordance with law. Otherwise, the flowback can
properly be disposed of in injection wells.
At this time, Maryland does not allow flowback or produced water to be discharged
to waters of the state, even with treatment. If EPA is able to develop pretreatment
standards for these wastewaters, Maryland will consider whether to allow these
wastewaters to be sent to a wastewater treatment plant.
THE COMPREHENSIVE GAS DEVELOPMENT PLAN
Regulatory process and mitigation
1. We concur with MDE’s view that the CGDP should be mandatory in Maryland
and its preparation is a prerequisite to an application for a well permit.
The Departments agree that the CGDP should be mandatory; however, for the
reasons explained below, the Departments now propose to allow a limited number of
exploratory well permits before the completion of the CGDP.
2. It is not clear whether the State can actually require a CGDP, or if the
requirements will be undermined by judicial decisions. Without the CGDP, many
protections will be lost.
The Departments believe that MDE has the legal authority to require a CGDP. The
Departments agree that it is a key element to ensure adequate protection. If it were
invalidated or rendered ineffective, the State would need to reevaluate the options for
adequate protection and may decide that HVHF should not be permitted in Maryland.
3. According the draft report, “If the State determines that the CGDP conforms to
regulatory requirements and, to the maximum extent practicable, avoids impacts
to natural, social, cultural, recreational and other resources, minimizes
unavoidable impacts, and mitigates remaining impacts, the State shall approve the
CGDP.” How will “the maximum extent practicable” be determined? The State
should describe a threshold at which it would reject a CGDP if it determines that
impacts are not sufficiently minimized or mitigated. How does the state plan to
balance the various interests and determine if a plan “conforms to regulatory
requirements and, to the maximum extent practicable?” Will the economic
burden on an applicant be part of the determination?
It is not possible to establish a threshold of impacts that would require disapproval of
the CGDP because every situation will be unique. Development and evaluation of the
CGDP will involve a balancing of the interests of the local residents and community
with the rights of property owners and leaseholders and impacts to the environment
and public health. The engineering and operational standards will apply to all well
permit applications, and will serve to control the impacts. The term “practicable” is
sometimes interpreted as “that which can be done without undue hardship,” so the
economic burden on the applicant can be considered, but is not determinative.
4. Approval of a CGDP should not amount to a pre-approval of a gas drilling permit.
Approval of the CGDP is not pre-approval of a gas drilling permit; rather, approval
of a CGDP is a prerequisite for the filing of an application for an individual
production well permit, which must be at a location approved in the CGDP.
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Decisions on applications for individual gas drilling permits will be made based upon
the information submitted in the individual application and the applicable rules and
regulations.
5. There should be no “fast tracking” of wetland and waterway permit approvals
merely because the locations of wetlands impacts and waterway and floodplain
impacts have been identified in a CGDP. Fast tracking and expedited review
shortchange the local citizens.
For wetlands and waterway permit applications, the Department sometimes requires
an alternatives analysis of the proposed project, including the "no action" and other
alternatives that avoid and minimize adverse impacts on wetlands and waterways
resources, with the analysis including an evaluation of alternatives that have the least
impact on public safety, adjoining properties, and the aquatic environment. Although
the CGDP will provide valuable information necessary for MDE's review of a
wetlands and waterways permit application, additional information may be
requested, on a case-by-case basis, related to the State's alternatives analysis or
other information requirements regarding avoidance and minimization of impacts to
wetlands and waterways resources. The CGDP does not in any way excuse
compliance with any of the procedural or substantive requirements of the wetlands
and waterways permits, and local citizens will be afforded all of their public
participation rights.
6. When can the collection of the two years of baseline monitoring begin relative to
the submission or approval of the CGDP?
The collection of the two years of baseline monitoring can begin at any time. Because
the collection of this site-specific data will be expensive, it is unlikely that the
applicant for a CGDP would begin this monitoring until the applicant was confident
that the location of the drilling pad would be approved. The applicant could,
however, take a chance on approval of the CGDP and initiate the baseline
monitoring before submitting a CGDP for approval.
7. Can the applicant apply for an individual well permit immediately after approval
of the CGDP?
The applicant can apply for an individual well permit for a well site in an approved
CGDP, but the application will not be complete until the applicant submits the 2
years of baseline monitoring.
8. We believe that the development of a comprehensive gas development plan has
the potential to not just protect natural, cultural, social and recreational resources,
but it could end up saving the gas drilling companies significant development
costs due to increased efficiency. In order to make the use of CGDPs more
attractive to industry, particularly if CGDPs are not made mandatory, we would
support the use of expedited permits and approvals.
The State expects that a high quality CGDP will minimize the need for costly and time
consuming permitting processes by virtue of avoiding and minimizing many of the
environmental impacts upfront. Although the CGDP will provide valuable
information necessary for MDE's review of permit applications, additional
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information may be requested, on a case-by-case basis. The CGDP does not in any
way excuse compliance with any of the procedural or substantive requirements of
other permit programs.
9. We would support the conservation of high value forest through easement or feesimple acquisition as a mitigation option for implementation of the no-net-loss of
forest recommendation given the lack of land in Western Maryland for
reforestation. We would recommend that the definition of high value forest
include inholdings within state forest lands, parcels surrounding existing large
protected tracts of forest, and key connectors and corridors linking large forest
blocks.
These are good suggestions and will be considered.
10. “Avoid, minimize and mitigate impact on resources as discussed in Section IV.”
Section IV does not address mitigation.
Each permitting program has specific mitigation requirements. In addition, the
resource agencies work together to identify the most appropriate mitigation
requirements based on the specific impacts. Mitigation is approached on a case-bycase basis to ensure that all impacts are adequately addressed.
Effectiveness
1. The study is unclear about how the cumulative impact of shale gas development
by multiple companies will be considered in the review of CGDPs.
Even the first CGDP will provide more information about cumulative impact than any
individual well permit application. Subsequent CGDPs will provide additional
opportunities to evaluate and reduce the cumulative impact, for example, through colocation of infrastructure.
2. We support the recommendation for a Comprehensive Gas Development Plan
(CGDP) to be prepared by the gas industry that plans for a development area prior
to considering each individual well. Such an approach makes sense for
maximizing efficiency and minimizing potential impacts to water quality of
source and receiving waters.
The Departments agree.
3. Using a Comprehensive Gas Development Plan will concentrate the adverse
impacts of shale gas development in a few places, creating intolerable levels of
negative impact on those who live there.
The goal of the CGDP is to reduce the cumulative impact of shale gas development
by minimizing the number of well pads, roads, and pipelines, and by locating these
surface disturbances in areas that will be least impacted by them, considering both
the ecological impact and the impact on people. The hypothetical “idealized
example” presented in Figure 1-1 of the Eshleman report with 54 wells on 36
contiguous acres of pads is not a real world scenario, nor would it ever be permitted
if it resulted in extreme impacts to residents or to a community. The process of
developing and approving the CGDP will provide an opportunity for considering the
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potential impacts of different development scenarios. Concentrated development will
not be approved at the expense of the well being of residents.
4. Integrated CGDPs (involving more than one company) are merely encouraged,
not required. This does not protect the public’s interest.
One company may prefer to defer gas development in Maryland, while another
wishes to move forward. It would not be fair to prevent a company from submitting a
CGDP just because a competitor was not ready to proceed with development of its
(the competitor’s) holdings.
Mapping and Shale Gas Development Toolbox
1. The CGDP should require geological mapping to cover the potential existence of
fault lines.
Most companies conduct various types of geological mapping prior to developing a
drilling plan in order to determine where fault lines occur and how this will affect
HVHF production rates. The Departments have decided that they will require, as
part of the CGDP, that the applicant perform and submit a geological investigation to
locate existing faults and fractures and abandoned wells in the area covered by the
CGDP. A similar geological investigation may be required for the limited number of
exploratory wells that may be permitted without a CGDP.
2. The CGDP will not be effective unless the data that goes into it is reliable. Data
collected by the industry should be compared to data independently collected or
confirmed by MDE and DNR, especially if two or more companies participate
jointly in the development of a CGDP. Industry data should not be accepted
without verification.
Most of the data to be considered for a CGDP will be data the State has collected and
provided to the applicant and the public, including GIS data. The exceptions are that
the applicant must also perform a rapid field assessment for unmapped streams,
wetlands and other sensitive areas and submit a geological investigation to locate
existing faults and fractures and abandoned wells in the area covered by the CGDP.
The adequacy and reliability of that data will be considered by the Departments. The
full Environmental Assessment will be done in connection with the application for
individual well permits. There is no two year planning requirement for the CGDP;
the application for an individual permit must include two years of background data.
3. The State should develop maps showing where Marcellus gas development,
including ancillary operations, is and is not to be allowed. Wetlands, flood plains,
steep slopes, rivers and streams, lakes, outcroppings, and local topographic
features should be shown.
The Shale Gas Development Toolbox will include maps with a significant amount of
information on these areas.
4. The Toolbox should include complete hydro-geological data for all fractured-rock
strata over Maryland’s Marcellus shale deposits, documenting location of
underground aquifers and understanding their movements. To ensure accuracy
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this data should not be collected by the applicant, but by contractors approved by
or employed by the State.
This would be valuable information for all areas of the State, and some research
along these lines was recommended in the reports of the Advisory Committee on the
Management and Protection of the State’s Water Resources. The research is
expensive and has not been fully funded. The State is pursuing the studies in phases.
As the information is developed, it will be published and potentially added to the
Toolbox if it is suitable for such purpose.
5. The Comprehensive Gas Development Plan should also include a review of all
past land uses, local and State Comprehensive plan consistency analysis and
relevant information about local zoning and land development regulations.
Past land uses that include drilling or subsurface coal mining will help inform the
CGDP and where this information is available, it will be provided. The Shale Gas
Development Tool box will work with local governments to provide the appropriate
links to program, zoning and land development regulations. The Toolbox may
include mapping data from local governments if it is available.
6. MALPF preserved property and MALPF easements should be considered in
planning and mapped in the toolbox.
This information will be included in the Toolbox.
Alternatives for exploratory wells
1. We need a set of temporary regulations that will allow for exploratory wells to
quantify the quality and quantity of the gas underlying the shale play in Western
Maryland.
2. The CGDP should be voluntary and should not apply to exploratory wells. It is
not reasonable to require the development of an extensive plan for long term
development in areas where there is no information on the viability of the project,
or indeed if the Marcellus formation in the area would support such a
development. It would also make sense to require some basic information before
doing any initial drilling and then requiring a very detailed document before
production can occur. If an exploratory well is allowed and it produces gas, it
should be permitted for production.
3. While a CGDP is reasonable on extremely large acreages like the Pennsylvania
state lands, no one in our organization can visualize how such a thing would work
when a thousand landowners may be involved and there are no proven reserves
here to encourage a company to engage in such a process. At the very least, the
industry needs to be permitted to drill enough wells under temporary restrictions
to prove the reserve before they are required to jump such a hurdle.
4. We have serious concerns about a mandatory Comprehensive Gas Development
Plan (CGDP) for at least five years. This requirement is premature; requiring it
after a company has drilled initial exploratory wells would make much more
sense. Shortening the time frame to two or three years would also allow for more
accurate forecasting. Bifurcating it to provide some basic information before
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doing any initial drilling and then requiring a very detailed document before
production can occur would be practical. It would also allow for a significantly
more substantive and accurate long term CGDP being submitted.
5. Without validating the need for a mandatory CGDP, a more practical approach
would be the permitting of one or more exploratory wells in accordance with
current state regulations to allow operators the opportunity to determine the
feasibility of further development. It should be noted that to begin the process of
drilling an exploration well, the operator must dedicate approximately four years
of resources and expense before obtaining any information on the viability of
production from the Marcellus formations in Maryland. This timing assumes the
noted policies, maps, and toolbox are in place.
Drilling and hydraulically fracturing an exploratory well would have impacts similar
to drilling and fracturing a production well. Moreover, if an exploratory well shows
good yield, it will probably be converted to a production well. For this reason, the
Departments initially proposed that CGDPs should be required for any well –
exploratory, offset or production. Commenters noted that basic information that can
only be obtained by an exploratory well would be necessary before a company could
write a CGDP. If a company were required to prepare a CGDP before drilling
exploratory wells, there would be a high likelihood that the information obtained
from exploratory wells would necessitate a substantively different CGDP. In the
informal solicitation30 of Commissioners on their reactions to the draft plan, 8 of the
12 Commissioners who responded indicated that it might be appropriate to allow a
certain number of exploratory wells before requiring the submission of a CGDP.
The Departments are therefore proposing that one exploratory well can be drilled
within a circular area having a radius of 2.5 miles centered at the exploratory well.
The same location restrictions and setbacks required for siting production wells will
be required for exploratory wells. No additional wells, exploratory or production,
can be drilled within that area until a CGDP has been approved. Absent a
determination by MDE that the exploratory well can be connected to a transmission
line without any adverse impact on wetlands, forest, or nearby residents, the
exploratory well cannot be converted to a production well until a CGDP for that area
is approved.
CGDP timeframe
1. The CGDP adds a time consuming and expensive planning for a driller who may
not even have obtained the leases, options, rights-of-way and other property
rights. It may have minimal environmental benefit. The standards for approval are
ill defined and the process could drag on and even be appealed to a court.
The State will provide criteria, mapping information and guidance upfront so that
drillers will have all of the information they need to make wise real estate and leasing
decisions. This should actually improve the ability of a driller to develop an
acceptable plan and have it readily approved since there will no unanticipated
conditions or constraints.
30
www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Survey_Commissioners_Final.pdf
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2. The time frame for a CGDP should be shortened to two or three years to allow for
more accurate forecasting.
If exploratory wells are allowed without a CGDP, as described above, a five year
timeline is not unreasonable.
3. Why should a CGDP that covers only five years of development remain in effect
for ten years?
Many factors could cause a company to delay implementation of its CGDP. The
Departments think that allowing 10 years is reasonable.
4. According to the UMCES-AL report the average well pad will be in place for at
least 30 years. According to this report, the plans will remain in effect for 10
years. Five years does not seem sufficient given the long-term nature of this
activity.
It is important to choose good locations for well pads because they will be in place
for a long time. The CGDP will identify the locations of surface disturbances such as
well pads, pipelines and roads. Permits to drill wells will only be approved if the
locations are consistent with an approved CGDP. To establish new locations, the
company would have to go through the CGDP process again.
5. The report indicates that an approved CGDP will remain in effect for 10 years.
We recommend a provision for renewal be added to the report language.
The Departments agree that one renewal for an additional 10 years can be granted if
the resource information is updated, and the locations initially approved do not
violate any more recently enacted location restrictions or setback requirements.
However, if a company has compiled a record of serious violations or has failed to
remediate any spills or releases properly, MDE can deny a renewal request.
6. Agencies should review the approved CGDP plan at the 5 year point to ascertain
whether any environmental conditions have changed that would require a CGDP
modification.
While this might add additional environmental protection, its usefulness must be
balanced against the legitimate need of a company to make long term plans. An
approved CGDP will be a public document, and anyone undertaking activities in the
area covered by a CGDP should be aware of it. In the event an application for an
individual well raises serious environmental concerns, it may be possible to deny the
permit or add protective provisions to the permit.
7. If one looks at the complete requirements to obtain a drilling permit, the permit
would require the development and approval of a five year CGDP plan, followed
by a lengthy approval process. The total time for the development and approval of
a CGDP plan is estimated at a minimum of 18 months. Assuming approval of the
plan, this would be followed by a minimum two years of pre-development
baseline data collection (pages 44 and F-1) on groundwater, surface water, and
both aquatic and terrestrial ecological resources prior to obtaining approval to
drill the initial well. The total time to perform the baseline study and obtain state
approval is estimated at 28 months.
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It is unclear how the commenter arrived at a minimum of 18 months to develop and
approve a CGDP. As currently proposed, the process gives the State 45 days to
review the initial submission and provides a maximum 60 day period for facilitated
stakeholder review. There may be additional reiterations of the planning, depending
on the quality of the initial CGDP submission. Following the facilitated stakeholder
review, there will be notice and a public meeting to present the CGDP. Following
that, the applicant can present the CGDP to the Department for approval. The
applicant is free to begin baseline monitoring before the CGDP is approved, but this
would be a costly undertaking that may need to be repeated if the location of the pad
were to be changed before final approval of the CGDP.
Public review process
1. The industry may ignore viable alternatives.
A reasonable number of alternatives should be considered, and reasons should be
given for rejecting alternatives.
2. When does the stakeholder review of the CGDP begin relative to the agencies’
initial review?
The State agencies and local government agencies will review the applicant’s draft
CGDP and provide comments to the applicant within 45 days. Following receipt of
the comments, the applicant may wish to revise the draft CGDP. For this reason, the
mandatory public review and approval process will not begin until the applicant
informs the agency that the draft is ready for public review.
3. This stakeholder review should not take place only at the request of the applicant.
The stakeholder review process is mandatory. It will not begin, however, until the
applicant informs MDE that the draft is ready for public review.
4. There should be adequate time for public review of the CGDP after the
completion of the stakeholder group process, and the applicant should be required
to provide notice to the public.
Notice will be given to the public that the CGDP is available for review and comment
and the date of a public hearing at which it will be presented. A comment period of 30
days beginning with the publication of notice will be provided, but the Department of
the Environment may, in its discretion, extend the comment period. Although the
CGDP is not a “permit” because it does not itself authorize any activity, in general,
under Section 5-204 of the Environment Article, the applicant for a permit pays the
cost of the newspaper notice, and the Departments would anticipate that this would
be the case for the CGDP.
5. Who will be responsible for determining who will be part of the “stakeholders
group”, how will stakeholders be identified, who will organize the meetings, and
who will pay for the facilitated process? Does this include landowners on
adjoining properties, who will also be adversely affected by noise, lights, air
pollution?
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We envision that DNR will be responsible for identifying the stakeholders, organizing
the meetings, and selecting the facilitator. The costs will be borne by the company
that submitted the CGDP.
6. Local planning, historic preservation, and heritage groups should be included as
stakeholders.
For a specific CGDP, these groups would be considered stakeholders.
7. Requiring the local governments to respond to a plan within 45 days is too short.
The 45 day review period should be sufficient to allow for a preliminary review that
would spot red flags like noncompliance with a county or town ordinance. Local
government would be included in the stakeholder group and be able to participate in
that process after the end of its preliminary review.
8. 60 days to review a comprehensive plan such as these with as many stakeholders
as these is exceedingly and totally unrealistic. There needs to be a lengthier
period of time.
With the toolbox information and a skillful facilitator, the review could very likely be
completed in 60 days or less. If experience proves otherwise, the time could be
extended.
9. This should include the statement –“minimization of impact on existing human
population and existing concentrated human population centers” as part of the
considerations.
The Departments agree that impacts to existing human populations and existing
concentrated human population centers are extremely important to consider. Many
of the setback requirements are intended to address these conflicts. The Departments
also believe the inclusion of a facilitated stakeholder review and public comment
period as a key step in the CGDP will provide an important venue to communicate
these concerns to industry and to identify solutions that will avoid and minimize these
impacts.
10. Allow applicants the opportunity to provide opportunities for meaningful public
input in pre-development stages.
The CGDP requires a facilitated stakeholder and public review of the proposed plan.
The State will review the submission in light of the stakeholder and public comments.
Planning principles
1. Will the State consider approving a CGDP near or adjoining state lines where
regulations in the adjoining state do not meet requirements of Maryland’s CGDP
process and regulations?
Maryland’s jurisdiction does not extend beyond State lines, and we would not expect
a CDGP to address activities outside Maryland. Any CGDP for activities in
Maryland will be considered on its merits.
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2. The planning principles for the CGDP should not reference state policies that
have not yet been enunciated, such as using directional drilling for stream
crossings and siting compressor stations.
The State develops and revises many policies, and will continue to do so. We should
not limit the planning principles only to policies that have already been developed.
3. The planning element “Sequence of well drilling over the lifetime of the plan that
places priority on locating the first well pads in areas removed from sensitive
natural resource values” is flawed. It implies that later wells can be located near
sensitive natural resources.
There are setback requirements and other practices to protect sensitive resources.
This planning element embodies the idea that, if we are to learn that any portion of
the regulations should be changed as a result of incidents, we would prefer those
incidents occur far away from sensitive resources.
4. We commend and strongly support the requirement for comprehensive gas
development plans (CGDPs) to address siting issues at the landscape‐ or
watershed‐scale. The CGDP approach addresses environmental impacts at a
regulatory scale appropriate to the state’s policy objectives; the alternative,
piecemeal permitting, is inadequate for minimizing adverse landscape impacts.
Further, comprehensive gas development planning is a necessary tool for
minimizing habitat losses and fragmentation, two of our top priorities for better
practices in the gas industry. In light of these considerations, we find it essential
to establish the type of comprehensive, systematic approach outlined in Section
III of the BMPs document.
The Departments agree.
5. We strongly endorse the Planning Principles set forth. These principles provide a
proper framework for BMP development in the context of the charge in Executive
Order 01.01.2011.11 to determine whether and how shale gas development in
Maryland might be accomplished without unacceptable adverse impacts to public
health, safety, the environment and natural resources.
The Departments agree.
6. The study proffers no Marcellus gas drilling on slopes greater than 15 percent;
consideration should be given to using a range of 10 percent – 15 percent so
assets and resources down-slope can be better protected.
There can be no drilling pad on land with a slope greater than 15 percent. The sites
proposed for pads in the CGDP will be individually reviewed and slopes less than 15
percent will be evaluated for suitability.
7. The Comprehensive Gas Development is one of the most important and
innovative aspects of the Commission’s report and addresses our organization’s
concern for the landscape scale impacts of unconventional shale gas development.
The Nature Conservancy’s Pennsylvania Energy Impacts Assessment released in
2010 highlighted these potential impacts and called for comprehensive planning
to minimize these cumulative impacts. The need for landscape level planning has
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also been identified by the Pennsylvania State University and the U.S. Geological
Survey as important in controlling the impacts from shale gas development. We
would urge that Comprehensive Gas Development Plans be mandatory and not
voluntary.
The Departments agree.
8. The recommendation is to “submit a CGDP for the area where the applicant may
conduct gas exploration or production.” We recommend that the area be defined
as that which can be served by shared infrastructure without having to over extend
that shared infrastructure to the point where it makes no economic or ecological
sense.
While the State encourages companies to share existing infrastructure, it cannot force
companies to participate with each other nor can the State restrict a company’s
planning efforts to a specific geography.
9. It is not clear whether the 2 percent limit on surface development within a high
value watershed applies to all development within the watershed or just the
surface disturbance caused by gas development. If it applies to gas development
over and above existing surface disturbance, high value watersheds that already
have some development may be impacted even with the 2 percent limit. If this is
the case, additional mitigation measures may be needed or that watershed should
become off limits to gas development.
The recommendation of the UMCES-AL report that activities be limited to 1 to 2
percent of Maryland’s land surface has been widely misinterpreted. The actual
recommendation was that “Cumulative surface development (including all well pads,
access roads, public roads, etc.) could be maintained at less than 2 percent of the
watershed area in high-value watersheds.” UMCES-AL report31 at 6-14. The State
has limited land use authority; the authority to enact zoning, subdivision, and other
land use restrictions lies with the counties and municipalities. Nevertheless, the
Departments adopt this recommendation as a planning principle to be followed in the
CGDP and to be used as a performance measure. The recommendation was based on
empirical evidence that aquatic habitat and aquatic diversity become degraded by
stormwater runoff well before the percentage of impervious surface reaches 10
percent and that brook trout are almost never found in watersheds where impervious
surface exceeded 4 percent. The loss of some species, particularly stream
salamanders, can occur in watersheds with only 0.3 percent impervious surface. The
UMCES-AL research showed a relationship between the amount of impervious
surface in a watershed and degradation of the stream. In order to provide an
adequate margin of safety, UMCES recommended a 2 percent surface development
threshold which they note can be achieved through the sensible application of best
practices and comprehensive planning. The UMCES research relied in part on
studies and analysis provided by the Department of Natural Resources:

31
32
Fact Sheet: Impacts of Impervious Land Cover on Maryland Streams32
www.mgs.md.gov/publications/report_pages/ADMIN_14-02-01.html
www.dnr.state.md.us/streams/pdfs/ImperviousFactSheet.pdf
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
S.A. Stranko et al. 2008. Brook Trout Declines with Land Cover and
Temperature Changes in Maryland. North American Journal of Fisheries
Management 28: 1223-1232.33
10. Maryland should not permit fracking to go forward in areas of the state, like
Garrett County, where adequate land use protections are not in place.
This is a matter that should be addressed by local governments. The State agrees that
local comprehensive planning and zoning could provide significant control over
where HFHV occurs. The State has also proposed a rigorous set of best practices
and setback restrictions that will be highly effective in minimizing harm to the
environment, economy and public health.
11. (B), (4), “Preferentially locate operations on disturbed, open lands or lands zoned
for industrial activity.” Departments should mandate that the state’s first wells be
drilled in industrial parks to assure minimal land-use conflicts.
The Departments would prefer the first wells be drilled on the least sensitive lands
but the State does not have the authority to mandate this.
12. It would appear useful, during both CGDP development and review, to consider
the tradeoffs between trucking of water and use of water pipelines (e.g., traffic
vs. land disturbance impacts).
The Departments agree that these issues should be considered at the CGDP stage.
13. The Pittsburgh-based Center for Sustainable Shale Development (CSSD) has
generated an interesting “performance standard” which calls for establishment of
an “Area of Review (AOR) ---which covers both the vertical and horizontal legs
of the planned well.” Among other stipulations, the standard mandates “a
comprehensive characterization of subsurface geology, including a risk
analysis’’ as related to “confining layers” preventing “adverse migration of
fracturing fluid”. [SOURCE: CSSD Performance Standards dated March 2013].
This “practice” is offered for consideration and relates to the controversy about
possible migration of “bad stuff” to “good water” even from 6,000 to 8,000 foot
depths.
Most companies conduct various types of geological mapping prior to developing a
drilling plan in order to determine where fault lines occur and how this will affect
HVHF production rates. The Departments have decided that they will require, as
part of the CGDP, that the applicant perform and submit a geological investigation to
locate existing faults and fractures and abandoned wells in the area covered by the
CGDP.
14. Recent reports from western US fracking sites call our attention to the possibility
of frack hits, blow outs that occur when a second drilling and fracking operation
goes off course and leads into a drilling hole already in operation. The combined
pressure results in the expulsion of fracking fluids under great pressure and spills
occurring over a much wider area than would have happened if the second drilling
33
http://clear.uconn.edu/projects/TMDL/library/papers/stranko_etal_2008.pdf
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operation had not "hit' the previously existing one. This calls into question the
wisdom of the Report's siting of many multiple wells on one fracking pad.
The Departments understand that drillers carefully plot the locations of their vertical
and horizontal boreholes reducing the risk that wells drilled from the same pad would
touch. There is a risk that a well will be drilled and contact an historic well that has
not been properly closed. By requiring the identification of historic and abandoned
wells during the CGDP process, this risk can be reduced.
15. The State is proposing a planning principal that the drilling activities comply with
local law and regulations, including zoning ordinances. Since the plan is
reviewed by the State, how will this determination be made?
During the initial review of the CGDP, local governments will have an opportunity to
review the plan to determine if the drilling activities comply with local law and
regulations. In addition, when applying for an individual well permit, the applicant
must produce written approval by the local zoning authority that all local planning
and zoning requirements have been met. COMAR 26.19.01.06C(11).
16. Reduce land use conflicts with adjacent properties. Protect Maryland’s prime
agricultural soils and prime farmland.
Avoidance of prime agricultural soils and farmland is desirable, but it must be
weighed against impacts on forests and sensitive ecological areas.
Compressor stations, gathering lines and other supporting infrastructure
1. Local zoning may not be honored because FERC can overrule local zoning by
preemption.
The Federal Energy Regulatory Commission has jurisdiction over interstate
gathering lines, transmission lines, compressor stations and storage facilities. The
commenter is correct that FERC could overrule local zoning for the siting of those
interstate facilities and infrastructure. FERC does not have jurisdiction over the
locations of well pads or wells, or intrastate facilities.
2. Changing the location of a compressor station or pipeline should require a formal
modification to the CGDP.
This is a complicated issue because of the shared federal and state regulatory
authority over transmission lines and compressor stations. The Departments will
inform FERC and the PSC of the role of the CGDP in Maryland’s natural gas
development regulatory process. Those agencies may not be bound by the CGDP,
but will certainly consider the CGDP.
3. The agencies should adopt a clearinghouse strategy that would bring the PSC into
the permitting process for the CGDP. The agencies and the MSAC should review
the process for permitting, siting, construction and operation of all pipelines and
ancillary development outside of the CGDP process.
The CGDP is not a permitting process, but rather a planning process for approving
locations in advance of permitting. The PSC has no authority over the location of
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pads or gathering lines. The commenter’s suggestion goes beyond the scope of the
Executive Order.
4. I advise caution on location of pipelines along roads because of the explosion
hazard.
The explosion risk of properly installed and maintained underground pipelines is low.
Modifications to the CGDP
1. If the applicant increases its total surface disturbance by 20 percent or greater the
applicant should be required to resubmit their application for the CGDP and begin
a new the process. Those applicants that increase their operations by less than 20
percent should be allowed to modify the existing application.
The CGDP will establish the locations of the pads, pipelines and roads, but will not
specify the details, such as the area covered by the pad or the width of the road,
except where those details are necessary to assure that harm is mitigated to the
maximum extent practicable. The draft best practices report recommended that
“Significant modification to the original plan, such as a change in location of a
drilling pad, or the addition of new drilling pads, will require the submission and
approval of a modified CGDP application. Modifications that cause no surface
impact, such as the installation of additional wells on an existing pad or a change in
the sequence shall be approved by the State upon request of the applicant.” If the
applicant disturbs more surface by widening a road, for example, there would be no
need to modify the CGDP unless the width of the road had been established to protect
a sensitive area. The Departments judge these to be reasonable provisions.
2. Adding wells to a pad should require a formal modification to the CGDP.
Additional wells on a pad would still have greater social and environmental
impact and could create intolerable levels of negative impact on those who live in
the "sacrifice zones."
Any new wells added to a pad will require the filing of a new individual well permit
application which would include a public comment process to address the concerns of
the affected, nearby residents.
CONTAMINATION OF DRINKING WATER
1. Any spills could contaminate surface and subsurface drinking water supplies. The
National Forest Service will likely ban fracking in the George Washington
National Forest, which lies in the Mountains of Virginia and West Virginia. The
reason: There is enough evidence to suggest that the process and the potential for
spills poses risks to the drinking water supply for millions of people, including
those living in the Washington, DC. (Article)
Spills from fracking operations could potentially contaminate surface and subsurface
water supplies, so it is very important to prevent spills, contain them if they occur,
and clean them up. Each applicant for a permit will have to submit a detailed spill
prevention, control and countermeasure plan and an emergency response plan. The
approved plan will become part of the permit, if it is issued. Many of the best
practices also operate to reduce the probability of a spill. Examples are the
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requirement to store wastes in tanks with secondary containment rather than in
ponds.
The location restrictions and setback distances are also designed to protect drinking
water. The Departments proposed significant setbacks in the draft report, and are
adjusting some setbacks based on comments and further consideration.
The new requirement is that a well pad cannot be located:
a. Within 1,000 feet of a wellhead protection area or a source water
assessment area for a Public Water System (PWS) for which a Source
Water Protection Area (SWPA) has been delineated. [Note that a similar
setback is already in effect for wellhead protection areas. COMAR
26.19.01.09G]
b. Within 1,000 feet of the default wellhead protection area for public water
systems for which a wellhead protection area has not been officially
delineated. [For public water systems that withdraw less than 10,000 gpd
from fractured rock aquifers the default SWPA is a fixed radius of 1000
feet around the water well(s).]
c. Within 2,000 feet of a private drinking water well; except that the well pad
may be located between 1,000 and 2,000 feet of a private drinking water
well if the applicant demonstrates through a hydrogeologic study that the
proposed well pad is not upgradient of the private drinking water well and
the owner of the private drinking water well consents.
d. Within 450 feet of any other stream, river, seep, spring, lake, pond, or
reservoir from which drinking water is drawn.
e. Within the watersheds of any of the following reservoirs:
i. Broadford Lake
ii. Piney Reservoir
iii. Savage Reservoir
Based on further review, the Departments have decided to establish a setback
specifically for springs that are the source of domestic drinking water to the residents
of the property on which the spring is located. The setback, measured from spring to
the edge of the well pad, shall extend to all lands at an elevation equal to or greater
than the spring discharge elevation, but not to exceed 2,500 feet unless a delineation
of the recharge area prepared by a registered geologist, with a report and data
supporting an alternate area, is submitted to the Department and the Department
approves an alternative area.
The Departments are also clarifying that no surface disturbance (road, well pad,
pipeline) may occur within Maryland’s State Parks, Forests, Natural Areas,
Wildlands and other DNR land units without the permission of DNR. These lands
were acquired by the State for their particular value and are managed for public
purposes, including maintaining, enhancing and protecting sustainable and diverse
wildlife populations, habitats, natural communities and ecologically sensitive areas,
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biodiversity, rare, threatened and endangered species, wildlife-dependent recreation
and other outdoor recreational opportunities. They also serve as a venue to educate
citizens on the value and needs of wildlife and plant communities. State forests help
reduce air pollution and protect our surface water and groundwater. All of these
public purposes will be compromised if surface disturbance were allowed in these
DNR-managed lands.
2. Methane concentrations in groundwater are higher near natural gas wells.
A recent article, A geochemical context for stray gas investigations in the northern
Appalachian Basin: Implications of analyses of natural gases from Neogene-through
Devonian-age strata, Baldassare et al., AAPG Bulletin, (February 2014), stated in the
Summary and Conclusions section:
Reports of alleged stray gas migration can be the result of preexisting,
and previously undiagnosed, methane in the shallow aquifer system, or
the result of gas well operations, or other anthropogenic activity. Gas
concentration variability in a water well over time can be the result of
changes in hydrostatic head induced by pumping or by seasonal
fluctuations in the water table. Alleged incidents of stray gas
migration require investigations at the site specific level and
evaluation and synthesis of multiple data types to determine the source
of the stray gas. Site-specific investigations should include definition
of gas and groundwater geochemistry and mechanism of migration.
Comprehensive predrill groundwater quality sampling is often
essential to distinguish preexisting natural gas in the aquifer systems
from gas-well activity-induced stray gas migration. Alleged stray gas
migration incidents must be monitored and sampled sufficiently
following specific methodologies and investigation protocols to
determine if the alleged incident is a natural condition or the result of
natural gas-well activity.
The Departments are aware of the peer-reviewed scientific journal articles which
report water quality data and assess whether there is a correlation between the
concentrations of methane and dissolved metals in well water and distance from gas
wells. Some of the articles show a statistical correlation and some do not. For
example, Dr. Avner Vengosh, in his presentation at the April 14, 2014, meeting of the
Advisory Commission, noted that he found no correlation between methane levels and
proximity to gas wells in Arkansas, but that he did find increased stray gas
abundance in drinking water wells within a kilometer of active gas wells in a part of
northeastern Pennsylvania. Based on isotopic fingerprinting and other factors, he
concluded that water wells near gas wells in northeastern Pennsylvania contained
Marcellus production gases or a mixture of Marcellus gases and other gases. He
wrote: “In cases where the composition of stray gas is consistent with the target shale
formation, it is likely that the occurrence of fugitive gas in shallow aquifers is caused
by leaky, failing, or improperly installed casings in the natural gas wells. In other
cases, hydrocarbon and noble gas data also indicated that fugitive gas from
intermediate formations apparently flowed up through the outside of the well annulus
and then leaked into the overlying shallow aquifers.” Vengosh et al., A Critical
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Review of the Risks to Water Resources from Unconventional Shale Gas
Development and Hydraulic Fracturing in the United States, Environmental Science
and Technology (2014).
It is known that methane can appear in drinking water wells in western Maryland
without any relationship to gas wells. The Maryland Geological Survey (MGS)
recently performed a pilot study to determine background (before horizontal drilling
and hydraulic fracturing) methane levels in drinking water wells in Garrett and
Allegany Counties. The results are consistent with other reported data that shows a
relationship between topography and methane content. MGS categorized wells as 1)
in valleys in coal basins; 2) on hilltops or hillsides in coal basins; 3) in valleys but
not in coal basins; and 4) on hilltops or hillsides but not in coal basins. The authors
report:
With respect to the four well-location categories targeted in this study,
… valley wells in coal basins had the highest proportion of detections
(11 of 15 wells, or 73 percent), followed by coal/hilltop+hillside (9 of
20 wells, or 45 percent), non-coal/valley wells (7 of 17 wells, or 41
percent), and non-coal/hilltop+hillside wells (7 of 25 wells, or 28
percent).
The authors also sampled a small number of wells approximately monthly, and found
that “The average percent difference from the median monthly methane
concentration in each well was between 20 and 30 percent, although individual
variations in each well were frequently larger.”
The Vengosh data present a convincing case for contamination of shallow drinking
water aquifers by stray gas within 1 km of active Marcellus wells in certain areas of
northeastern Pennsylvania. Data from Arkansas indicate that methane concentration
in shallow drinking water aquifers does not show an increase with proximity to
natural gas wells. During the Advisory Commission’s April 14, 2014, meeting
Dr. Vengosh said he does not know why methane is higher in drinking water wells
near gas wells in Pennsylvania, but not in Arkansas. The wells were operated by
different companies. In Pennsylvania air drilling has been used instead of drilling
with mud because it is faster; he speculated that mud drilling may result in better
casing and cement. There are geological differences, but there is no strong evidence
to say whether the difference lies in better practices or different geology.
If practices lessen the chance of methane release, a combination of practices and
setbacks could work together to protect shallow drinking water aquifers. The
Departments are proposing specific well casing, cementing, testing and repair best
management practices to minimize the rate of well failure and the associated
potential for methane migration. These, combined with a significant setback and
monitoring requirements, are appropriately protective of drinking water wells.
3. Naturally fractured shale is not an impermeable layer, as claimed by industry.
Marcellus shale is porous as evidenced by the fact that methane and other gases are
held within its pore spaces. Any fractures occurring within a shale bed, whether
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natural or induced through HVHF, will increase the ability of shale to transmit gases
and liquids.
4. Research suggests that the treatment of shale gas waste by treatment plants raises
downstream Cl− concentrations but not TSS concentrations, and the presence of
shale gas wells in a watershed raises downstream TSS concentrations but not Cl−
concentrations.
The discharge of shale gas wastewater through municipal wastewater plants in
Maryland is not currently allowed. If EPA adopts pretreatment standards for shale
gas wastewater, MDE will reconsider whether it should be permitted. Removal of
dissolved solids, including Cl-, is a necessary treatment step if fracking wastewater is
to be discharged to freshwater surface waters.
An increase in total suspended solids is a likely consequence of sediment transport
from disturbed land. Given the infrastructure needed to support shale gas
development, it is imperative that proper care and planning go into developing an
efficient network of pipes to collect gas with minimal disturbance to the landscape.
Existing roadways and other rights of way should be used to the fullest extent
possible. Proper erosion and sediment controls will also help reduce the transport of
sediment from the construction site.
5. Currently available data indicate that the depth to the base of fresh-water aquifers
in Garrett County varies greatly, from 400 ft to more than 1,000 ft below land
surface, and it is not possible to predict with any confidence a depth to the base of
fresh ground water at any given location. Therefore, we strongly recommend that
this depth should be determined at each drill site. The best way to determine the
depth to base of fresh water is to drill a pilot hole and run a suite of geophysical
logs (including but not limited to electrical resistivity, porosity, and spontaneous
potential logs) that can be used in conjunction with other well data to accurately
characterize the subsurface fluids. In order to determine the base of the deepest
fresh-water aquifer at each site, it is recommended that a vertical pilot hole be
drilled and evaluated at each drilling site and that appropriate geophysical logs be
run in the hole. This determination is best made in a small-diameter hole to
minimize effects of drilling fluids on the measurements. If a separate pilot hole is
not drilled, then at a minimum, the BMPs should specify that geophysical logging
must include all zones from the bottom of the well to the ground surface (to
ensure that logging covers the relatively shallow portions of the hole, not just the
gas-bearing sections).
The Departments support the practice of drilling a pilot hole as a way to detect large
underground voids and other subsurface characteristics such as depth to the base of
fresh-water aquifers. One pilot hole per pad will be required as a prerequisite for
drilling. This pilot hole needs to be fully cased or properly abandoned to ensure
pathways between shallow and deeper aquifers are not introduced.
Current Maryland regulations require that the driller, when drilling the gas well,
conduct an electrical induction and gamma ray log to determine depth of fresh water
zones. COMAR 26.19.01.10O. This requirement will be retained.
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6. The majority of “wastewater” remains underground and the poorly understood
technology for rock fracturing leaves us vulnerable to polluting our aquifers. The
report does not address in any way if such introduction into the aquifers could
ever be alleviated.
The available scientific evidence indicates that the possibility that fracturing fluids
would migrate upward through the overlying rock formations to reach drinking water
aquifers is extremely remote. In a highly faulted area, the risk would be higher, but
would still be low, and in the presence of numerous abandoned wells, the risk could
be appreciable. The Departments proposed in the draft report that maps of
abandoned gas wells be consulted as part of the CGDP process. Because not all such
gas wells and all faults are known, the Departments have decided to require a
geological survey of the area covered by the CGDP to help identify them. At a
minimum, the geological survey will include location of all gas wells (abandoned and
existing), current water supply wells and springs, fracture-trace mapping, orientation
on the location of all joints and fractures and other additional geologic information
as required by the State.
7. Recent studies by Duke University researchers have verified by isotopic
fingerprint methodology that methane gas migrates upwards through fractures
from in the Marcellus formation in Pennsylvania water wells located within one
kilometer of natural gas wells and contaminates water wells and aquifers. The
Departments must review and significantly enlarge their setback requirements.
More importantly, we strongly support programs to require the development and
continual evaluation of baseline data on methane in water wells and aquifers in
Western Maryland including the isotopic fingerprint of the methane. We believe
that the need to pretest water well and aquifer samples within a kilometer of
leased mineral rights for a number of elements along with isotopic fingerprinted
methane must be made a requirement of MSGD and to continue periodically over
the life of the well.
See answer to comment 2. Pre-drilling and post-drilling monitoring will be required.
Isotopic analysis for methane can only be performed if there are high enough
concentrations of methane. It will be required if circumstances warrant.
8. Gas migration from the Marcellus formation may be followed by brine containing
liquids in the future that contain any number of elements and radioactive isotopes
to further contaminate water wells and aquifers.
There is some evidence from areas in northeastern Pennsylvania that, unrelated to
any gas well activity, deep brines may have mixed with shallow aquifers, suggesting a
natural hydrogeological connection between the shallow and deep aquifers.
Geochemical evidence for possible natural migration of Marcellus Formation brine to
shallow aquifers in Pennsylvania, Warner, et al. (PNAS 2012). In his review article,
Dr. Vengosh states that it is conceivable that stray gas from Marcellus wells could
potentially be followed by a flow of hydraulic fracturing fluids and saline formation
waters to overlying shallow aquifers. He noted, however, that "groundwater sites in
areas affected by stray gas contamination near shale gas sites in northeastern PA
have not to our knowledge shown signs of salinization induced directly by leaking
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natural gas wells" and that further study would be needed. A Critical Review of the
Risks to Water Resources from Unconventional Shale Gas Development and
Hydraulic Fracturing in the United States, Vengosh et al. (Environmental Science and
Technology, 2014, section 2.2)
9. The Departments should require monitoring of all water wells within 2500 feet of
a vertical borehole before, during and after drilling and operation.
In the Eshleman Report, Recommendation 3-C of paragraph Q (page 4-32) and
paragraph B in Section 4 (pages 4-6 and 4-7) support monitoring within 2500 feet of
drilling activity. The Departments propose to accept this recommendation. The
recommendation clearly requires pre and post drilling testing. Requirements for
monitoring during drilling and during gas production will be included in the well
permit. Additional monitoring is likely to be required if there are observed changes in
water quality or evidence of a release of contaminants.
10. If more than one industry operator is working in the same area, the problem
becomes more complex in assigning responsibility for a groundwater
contamination and could lead significant delays while trying to establish
responsibility. Possible solutions:
a. require the industry to develop the hydrology data for the areas in which
they have lease holdings;
b. develop aquifer data at each well site
c. use tracers that are unique to each operator.
Because multi-well pads are common, it is unlikely that two different operators would
be within 2500 feet (the presumptive impact area) of a drinking water well. If this
situation were to develop, the presumption would apply to both companies. The
Departments are now proposing to require applicants for CGDP approval to do a
geological investigation of the area covered by the CGDP to locate existing faults
and fractures, as well as abandoned wells. Research is ongoing to identify potential
tracers and evaluate their usefulness. In the future, the Department of the
Environment will consider whether to require the addition of tracers to fracturing
fluid.
11. We believe that liability of water well contamination within 2500 feet of a drilled
gas well must be incorporated into the permitting process and the time period
extended beyond one year of the drilling activity to ensure water quality and
public health are protected. A process must be developed to deal with and assign
responsibility for unexpected problems especially if more than one industry
operator is working in the same area.
The General Assembly limited the presumptive impact area to 2500 feet and 365 days
after the last event of well drilling, completion, or hydraulic fracturing. Outside of
that time and distance, a person would have to demonstrate that the contamination
was caused by the actions of one or more gas operators. Under the severance tax bill
(SB535) that was introduced in the General Assembly in 2014, MDE could use the
proceeds of the severance tax to address immediate threats to public health or
welfare, and seek compensation afterwards. The bill did not pass, but the
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Departments will continue to search for ways to avoid the potential problem cited by
the commenter.
12. Allowing the oil and gas industry to ride out this fracking treadmill in Maryland
would turn the state into a pincushion of fracked gas wells. Over years and
decades, these wells would age, degrade and be abandoned, creating pathways
through which injected chemicals and natural contaminants can seep into
underground sources of drinking water.
Maryland’s best practices and financial assurances would ensure proper closure of
all depleted wells.
13. The Culpeper Basin underlies the Poolesville Area Sole Source Aquifer, the
primary source of drinking water for the area, as well as geological formations
such as the shale barrens, the serpentine barrens and the diabase bedrock
formation, which provide rare and unique habitats within Montgomery County.
Protection of such resources are included in our local land use, zoning, and forest
conservation codes and laws. Currently, hydraulic fracturing is not an allowed use
in Montgomery County. As part of the Marcellus Shale Safe Drilling Initiative,
we request the addition of a statement to indicate that the State will not seek to
preempt local zoning and land use controls.
Current Maryland law requires MDE to deny the permit if the applicant has failed to
receive applicable permits or approvals for the operation from all State and local
regulatory units responsible for air and water pollution, sediment control, and zoning
( Environment Article, § 14-108). Similarly, the regulations require the applicant to
submit written approval by the local zoning authority that all local planning and
zoning requirements have been met (COMAR 26.19.01.06C). There is no proposal to
change these requirements.
14. The report specifies that the vertical casing extend below the “deepest known
stratum bearing clear water” by a minimum of 100 vertical feet. This vertical
distance seems small. Casings should extend at least below the brine level, and
we’ve seen a study for the European Commission calling for a large distance of
600 meters (1,950 feet).
Only the surface casing is required to be run and permanently cemented to a depth of
at least 100 feet below the deepest known stratum bearing fresh water. Intermediate
casing and production casing must be cemented to isolate other fluid (liquid or gas)
bearing formations.
15. The setback distances in general sound okay, but when dealing with drinking
water reservoirs, such as the Frostburg Reservoir and others in Garrett County, the
distances should be greater than those recommended by Eshleman and Elmore. If
horizontal boreholes can extend 7000 feet, I think that the setback distance from
key drinking water resources should be at least 7000 feet.
Upon reconsideration, the Departments have decided that a well pad may not be
located anywhere within the watersheds of any of the following reservoirs: Broadford
Lake (serving Oakland); Piney Reservoir (serving Frostburg); or Savage Reservoir
(serving Westernport). It is the activity that occurs at the well pad that has the
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greatest potential to release pollutants that could contaminate drinking water. In his
presentation to the Advisory Commission, Dr. Vengosh said that there is no evidence
so far of contamination of drinking water by the upward migration of fracking fluid
or flowback, nor evidence of saline contamination of drinking water that might be an
early indication of such migration. Evidence indicates that a vertical separation of
the order of 2,000 feet would result in a remote risk that properly injected fluid would
result in contamination of fresh groundwater. Because the separation between the
bottom of the reservoirs and the laterals that might be drilled in the Marcellus shale
is greater than 2,000 feet, the laterals need not be setback from sources of drinking
water.
16. The UMCES-AL report states that, since the freshwater/saltwater interface has
not been mapped in Maryland, the prudent approach would be to rely on the 2,000
ft criterion to provide an adequate margin of safety. Specifying vertical depth
offsets presumes that the physical characteristics of geological units remain
unchanged. Assuming such a statically safe buffer zone is questionable. Changes
in the vertical permeability will occur and cannot be ignored. This occurrence is
dynamic because the changes migrate upward with time.
The instrumentation used during the drilling of the pilot hole will measure the
freshwater/saltwater interface. It can also be measured in drilling individual gas
wells. There is no evidence that changes in the geologic structure in the estimated
range (200 ft – 2000ft) of the freshwater/saltwater interface will occur.
ENVIRONMENTAL ASSESSMENT AND ENVIRONMENTAL IMPACT
STATEMENTS
1. The preliminary Environmental Assessment for the CGDP addresses the ancillary
facilities as well as the well pad, but the Environmental Assessment for the
individual well permit addresses only the well and well pad. The ancillary
facilities will escape full environmental assessment under Env. Code Section 14104. The indirect and cumulative impacts of ancillary facilities and infrastructure,
such as gathering lines, compressor stations and interstate pipelines should be
considered, even though the state does not currently have the ability to regulate
these.
Under the proposed best management practices a CDGP must be approved before
any permit can be issued for a well. The purpose of the CGDP is to evaluate and
minimize the cumulative impacts associated with all aspects of unconventional gas
well development, including ancillary infrastructure. Practices such as sharing
infrastructure and ancillary facilities, where possible, within and between various
drilling companies will be required. The CDGP process therefore ensures that
cumulative impacts are addressed in advance of permit issuance for any individual
well site.
2. It appears that a full environmental assessment may not be required for both the
CGDP and the individual permit.
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Many of the current requirements for the State’s environmental assessment will still
be addressed by the CGDP in addition to the full environmental assessment required
with any permit application.
3. The CGDP must be similar to a full Environmental Impact Study (EIS) which
takes cumulative impacts and viewsheds into account, rather than a form of
abbreviated Environmental Assessment.
Similar to an EIS, the purpose of the CGDP is to reduce or minimize cumulative
impacts to surface waters, ground water, development projects, conservation
activities, and other natural, social, cultural, and recreational activities. By
examining the impacts and considering alternatives, the best locations can be
identified. Though the minimum recommended setback for Marcellus shale drilling
related infrastructure is 300 feet, additional setbacks will be considered to protect
viewsheds. The State also anticipates that the CGDP process will be iterative in that
a series of alternatives will be considered and stakeholders will be consulted before a
final plan is approved.
4. The State has acknowledged that the current guidelines for an Environmental
Assessment are inadequate. The State should require the same type of statement
of environmental impact for all unconventional natural gas development as it does
for leasing of state land for drilling.
The legislature established standards for the decision to lease State land for oil or
natural gas production that are different from the standards for issuing a permit for
an oil or gas well. Section 5-1702 of the Natural Resources Article requires that
Board of Public Works request State agencies to prepare an environmental, fiscal,
and economic impact statement before it may solicit bids for or award any lease for
production of oil or natural gas from beneath lands or waters of the State. In
addition, the production activities must adhere to all federal, state and local
environmental laws. Section 14-104 of the Environment Article requires an applicant
to submit an environmental assessment for the purpose of evaluating an application.
The distinction between these two laws is that they are established for different
purposes and move through different decision processes.
State lands owned by DNR are acquired and managed for their high conservation
values, sensitive natural resources and their public benefits. These are public assets
held in public trust, and as such, the Board of Public Works requires the additional
information established by Section 5-1702. The revised permitting process proposed
by the agencies, which includes revision of the environmental assessment guidelines
and requires the development of a Comprehensive Gas Development Plan, will
produce comparable assessments. The Comprehensive Gas Development Plan
addresses area-wide environmental impacts of multiple well pads and includes a
rigorous multi-agency and stakeholder review. Concurrent with this review will be
an analysis of impacts and alternatives. Similar requirements are associated with the
many permits required for an individual well. There will be more similarities
between these two review processes than dissimilarities once the regulations are
revised.
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5. Are there regulations for basic requirements for an environmental assessment?
Are the requirements similar to NEPA?
Maryland regulation does not lay out the specific items that must be addressed by any
environmental assessment. These are contained in guidance that will be updated.
Environmental assessments go through a public process as part of the permitting
process whereby stakeholders can ensure they are complete.
While titled the same in the current Maryland “Application to Drill,” the state's
environmental assessment is not related to the Environmental Assessment required
under NEPA. State regulations do not require either an Environmental Assessment
(EA) or Environmental Impact Statement (EIS) as defined under NEPA for gas well
permits. The proposed requirement of a comprehensive drilling plan as a Best
Management Practice for natural gas development in Maryland, however, will
address some of the significant environmental factors, including cumulative impacts
that are the core of the NEPA EIS and EA processes. Additionally, the current state
regulatory processes that control the specific activities required for production and
transportation of natural gas, e.g. wetlands and waterways permits for stream
crossings, not only require an assessment of environmental features as part of the
application process, but also function to protect environmental assets.
6. The Environmental Assessments should include an analysis of alternatives and
past land uses.
The Comprehensive Gas Development Plan, as recommended, will include an
alternatives analysis. Historic wells will be identified and setbacks observed. The
recommendations for the CDGP also require a consideration of identified historic
cultural resources.
7. I know that the natural environment, is a focus of the Department of Natural
Resources, but there seems to be more concern with the survival of small
populations of endangered species, than we do about the disrupting the lives of
people.
The Department of Natural Resources recognizes that there are many irreplaceable
resources that could potentially be impacted by unconventional gas well development
that include sensitive habitats, plants and animals, and, just as importantly, the health
and quality of life of the affected people. DNR is committed to working with the
Maryland Department of the Environment and other state and local government
agencies to avoid and minimize all of these impacts, should the decision be made to
proceed with Marcellus development. Also, as part of Governor O’Malley’s
Executive Order, the Departments must undertake public health and economic studies
to evaluate the impacts of Marcellus shale gas drilling on the community. In
addition, both noise and road traffic are considered in Maryland’s best management
practices and more stringent provisions may be included in permits to address sitespecific conditions.
8. The Government Accountability Office could not quantify the risks of shale gas
development because (1) it couldn’t predict where the wells would be
constructed; (2) not all operators use best practices to the same extent; (3) there
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are few studies comparing pre- and post-development conditions; (4) changes to
laws and regulations will affect future activities; (5) risks will vary across
business practices, which may vary among companies. Without this, GAO could
not conclude that fracking is “safe.”
The GAO took a nationwide view and therefore was considering a patchwork of
different state programs. This variability in regulatory programs between the states
makes it difficult to assure that adequate safeguards are in place nationally to
address risks associated with unconventional gas well development. Maryland
specifically, however, is conducting a risk assessment in order to determine where the
greatest risks to human health and the environment exist in order to focus our efforts
to minimize these risks. This is in addition to the following actions taken to address
the stated concerns:
(1) The State is requiring various setbacks to protect human and environmental
health as well as requiring the CGDP which considers cumulative impacts across
the landscape;
(2) The State has developed a uniform set of best management practices to protect
human health and the environment as well as a compliance program intended to
ensure consistency with required BMPs that are a part of the approved permit;
(3) The Departments recommend requiring 2 years of pre-development baseline
monitoring and continued monitoring after development begins. MDE and DNR
will use such monitoring data to help identify whether negative impacts have
occurred as a result of drilling activities. This is in addition to a baseline
monitoring network (both ground and surface waters) already put in place during
2013.
(4) Any changes to laws will only serve to strengthen, not undermine, all of the
protective measures Maryland is putting into place; and,
(5) Again, and as stated above, Maryland is developing both best management
practices and a compliance program to minimize risks associated with
unconventional gas well development.
9. The minimum 2-year pre-development baseline data needs to be a mandatory part
of the CGDP or the Departments need to require a comprehensive Environmental
Impact Statement (EIS) to compile baseline data to access cumulative impacts and
mitigation strategies.
The 2-year pre-development baseline data is a mandatory element of the individual
well permit. An application to drill a well is not complete until the baseline data has
been collected and submitted to the State. It should not be made a mandatory element
of the Comprehensive Gas Development Plan, because the purpose of this plan is to
identify appropriate well pad locations. This will allow industry to initiate predevelopment baseline monitoring in a timely manner as a precursor to filing a permit.
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EARTHQUAKES
1. Fracking causes earthquakes
a. The independent studies conducted by University researchers across the
state of Texas have determined that fracking causes earthquakes of 4.0 and
higher within miles of fracking sites. Insurance companies do not cover
earthquake damage in Maryland.
b. Hydraulic fracturing has been definitively linked to earthquakes in Ohio.
c. Fracking by its very nature brings an increased incidence of earthquakes,
even in areas of the world where earthquakes had been nonexistent.
Fracking drills a series of deep holes in the earth’s crust and in so doing
creates areas of weakness. Frequent earthquakes result in many areas
where extensive fracking has taken place. Recently fracking was
discontinued in the United Kingdom because of earthquake occurrences.
The act of fracturing and propping open the fractures in the Marcellus Shale beds
will create microseisms (faint earth tremors), just as activities at quarries throughout
the State do. However, these microseisms typically are not felt nor do they cause
damage. Both the Texas and Ohio earthquakes have been definitively linked to well
injection sites, not fracking wells. As explained in a recent “Man-Made Earthquakes
Update”34 from the Unites States Geological Survey (USGS),
Many questions have been raised about whether hydraulic fracturing
— commonly known as “fracking”— is responsible for the recent
increase of earthquakes. USGS’s studies suggest that the actual
hydraulic fracturing process is only very rarely the direct cause of felt
earthquakes. While hydraulic fracturing works by making thousands of
extremely small “microearthquakes,” they are, with just a few
exceptions, too small to be felt; none have been large enough to cause
structural damage…. [U]nderground disposal of wastewater coproduced with oil and gas, enabled by hydraulic fracturing operations,
has been linked to induced earthquakes.
An investigation has begun of earthquakes that occurred in early March 2014 in Ohio
to determine if they could have been caused by hydraulic fracturing. The
Departments will follow this investigation closely.
Underground disposal of wastewater from oil and natural gas production occurs in
Class II injection wells. There are no Class II injection wells in Maryland and none
is being considered.
Earthquake insurance is offered as a rider just as flood insurance is offered as a rider
in Maryland. This is typical nationwide.
Fracking was suspended in the UK for about one year due to safety concerns. An
expert panel reviewed the information and concluded that fracking could continue
with the existing regulations in the UK. This suspension ended April 2012.
34
www.usgs.gov/blogs/features/usgs_top_story/man-made-earthquakes/
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Additional information can be found in these articles:
Kim, Won-Young, “Induced seismicity associated with fluid injection into a
deep well in Youngstown, Ohio.” Journal of Geophysical Research v118:7
(2013), p.3506-3518.
Frohlich, Cliff, “Two-year survey comparing earthquake activity and
injection-well locations in the Barnett Shale, Texas.” Proceedings of the
National Academy of Sciences of the United States of America.
DOI:10.1073/pnas.1207728109.
2. The report lacks any substantive analysis regarding potential risks of fracking and
geologic faults. Seismic events can release the fracking fluids that are intended to
be contained.
All known geologic faulting in Garrett County is 250 million years or older. Faults
this old are generally not seismically active.
3. Pre-existing planes or surfaces of weakness within the overlying shale influence
the direction of upward fracture migration. The next earthquake could be
triggered when the upward migration of a zone of fractures or enhanced porosity
intersects the plane of an active fault zone and then follows this plane of weakness
preferentially. This would essentially “lubricate” the opposing faces of the fault
and trigger the next earthquake.
The Departments acknowledge that pre-existing faults and strata discontinuities have
the potential to conduct or allow migration of materials along those fault lines. The
Departments do not concur that any migration of fluids would lubricate the historic
fault structures that have been inactive for 250 Million years.
EMERGENCY RESPONSE
1. Under the BMPs, company emergency response plans must include information
on specially trained crews that can arrive within 24 hours of a blowout, fire or
other accident.
a. Twenty-four hours is an eternity when a high-pressure drilling operation
malfunctions and toxins are spewed freely. That BMP is insufficient to
protect everything in the well’s path: workers, nearby residents and the
environment.
b. The BMPs should require plans for a 12 hour emergency response plan as
24 hours is much too long in case of a blowout, fire or other accident.
c. Maryland should require an eight (8) hour or less response to an incident.
d. The 24-hour emergency response by drillers is irresponsible and
inadequate and all drillers should have methods in place locally to fix
issues within a 4-hour timeframe.
e. Trained crews should be required to arrive immediately.
The draft best practices report stated that operators shall, prior to commencement of
drilling, develop and implement an emergency response plan, establish a way of
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informing local water companies promptly in the event of spills or releases, and work
with the governing body of the local jurisdiction in which the well is located to verify
that local responders have appropriate equipment and training to respond to an
emergency at a well. Before any drilling is permitted, local emergency response
personnel will receive training so that, in the event of an emergency, they can remove
the injured and secure the area until specially trained personnel can arrive. In the
event of a release of pollutants that may pose a risk of harm to nearby residents or
buildings, they will assist in evacuations. It is likely that company personnel will be
present or nearby and able to manage the incident. In the event of a well blowout,
fire, or other incident that personnel at the site cannot manage, the operator must be
able to have specially trained and equipped personnel at the site within 24 hours.
Emergency response personnel at MDE have initiated discussions with county
personnel to explore the best ways of providing appropriate training and to explore
the possibility of regional response capability so that response time can be shortened.
In addition to requiring emergency response and communications plans, other BMPs
establish well integrity and pressure testing, casing/cementing requirements,
monitoring requirements, blow out prevention, closed loop systems, secondary
containment, no-discharge pads, setbacks and site security measures. These BMPs
reduce the risk of incidents and releases of pollutants and provide a measure of
protection to the community.
2. The security and social costs to our rural communities if drilling occurs must be
considered. An influx in population creates demand on police, fire and EMS.
These services are paid for by local taxpayers and sometimes the people are
volunteers. They are not trained for blow-outs - nor do they know how to handle
accidents dealing with gas-well chemicals. "A list" will not help them or me if a
blow-out occurs on a dead-end road. And a few days worth of training sponsored
by the gas company does not cut it.
The economic study being completed by the Regional Economic Study Institute at
Towson University will provide estimates of the number of workers and the number of
truck trips that might be expected from shale gas development in western Maryland.
This will provide a way to estimate the magnitude of any impact. The Maryland
Department of the Environment’s Director of Emergency Management has spoken
with his counterparts in Pennsylvania and is sharing information with local
governments so that they can assess their capabilities and explore ways to cooperate
to provide appropriate training and equipment. Information about chemicals brought
to the site will be available in advance to emergency response personnel and, as
noted above, local emergency response personnel will receive training so that, in the
event of an emergency, they can safely remove the injured and secure the area until
specially trained personnel can arrive.
3. Rural areas with aging populations such as Allegany and Garrett Counties are
challenged to find adequate numbers of emergency responders, as well as
providing training and equipment. The cost of this additional responsibility should
be borne by the drilling companies.
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The Departments anticipate that drilling companies or an industry group will assist
with training and will identify whether special personal protective equipment will be
required for the work local emergency responders will be expected to do. The Center
for Sustainable Shale Development (CSSD) has developed initial performance
standards for operators that represent consensus on what is achievable and
protective of human health and the environment. One such standard reads “In
preparation for any spill or release event, Operators shall prior to commencement of
drilling, develop and implement an emergency response plan, ensure local
responders have appropriate training in the event of an emergency, and work with the
local governing body, in which the well is located, to verify that local responders
have appropriate equipment to respond to an emergency at a well.” If special
equipment is necessary, the State will work with the local governments to find
resources from the operators or other sources.
4. In the event of accidents, spills, or any emergency situation, first responders have
a right to know what dangerous materials they are in contact with.
Information about chemicals brought to the site will be available in advance to
emergency response personnel. In addition, the Departments are proposing a
streamlined way for any physician diagnosing or treating a patient to obtain
information about exposures.
5. There is no detailed “best practice” regarding safety planning. The Natural Gas
Industry best practice is to clear the area, call 911 and watch it burn.
The UMCES-AL report recommended that gas well permit applicants should be
required to develop site-specific emergency response plans, taking into account that
the optimum response may differ depending on the season of the year and the
topography of the site. The Departments accepted this recommendation.
In situations where there is an immediate risk to human health and safety, the best
practice is to evacuate the area and contact emergency personnel. Also, burning or
flaring gas is sometimes the best way to manage a gas release in the short term.
Burning natural gas releases mainly carbon dioxide and water.
6. The industry, and gas compressors in particular, is vulnerable to terrorist attack.
Aboveground pipelines, including those entering and exiting compressor stations,
have been identified as vulnerable to terrorist attack. Damage to the pipeline could
cause a fire that burns until the escaping natural gas is consumed. Valves exist along
the pipeline to isolate the damaged section and limit the amount of gas that escapes.
A break on a major pipeline could also cause damage by disrupting the flow of
natural gas to customers.
Considerable attention has been paid to pipeline security in recent years and industry
groups have issued guidance to their members. The Transportation Security
Administration has established the Pipeline Corporate Security Review (PCSR)
Program. Conducted by the Pipeline Security Branch staff, the PCSR Program is an
on-site security review with a pipeline company. PCSRs help establish working
relationships with key security representatives in the pipeline industry as well as
provide PCSR staff with a general understanding of a pipeline operator's security
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planning and implementation. Data obtained from PCSRs aid in establishing a
baseline against which to evaluate minimum security standards in the pipeline
industry and identify coverage gaps. PCSRs help to identify and share smart
practices observed throughout the industry.
7. "Spills . . . cleaned up as soon as practicable." Too vague –allowing time for spills
to spread and contaminate further.
The quoted section refers to spills that occur on the drill pad, which is lined and
surrounded by a berm. There is a low probability that the spill would spread and
cause contamination off the pad. “Practicable” is a term often used in laws and
regulations. It is used interchangeably with “feasible” and describes an idea or
activity that can be brought to fruition or reality without unreasonable demands.
Each spill event is unique and it is not possible to establish a single rule for when
cleanup must be completed. Current Maryland regulation COMAR 26.19.01.02
states:
In addition to any other notifications required by law or permit, the
permittee shall report to the Natural Resources Police Force 24-hour
Communications Section at (410) 974-3181 or (800) 628-9944
immediately, but not later than 2 hours after detection of, any condition
such as fires, breaks, leaks, escapes, spills, overflows, or other
occurrences that create a safety or pollution hazard. The permittee shall
remain available until clearance to leave is given by the appropriate
officials designated by the Department.
We are not proposing to repeal the spill notification regulation. This will act as an
additional check on prompt cleanup.
8. The BMPs should require that drilling operations report chemical releases to the
federal Toxic Release Inventory, or to a publicly accessible on-line database
managed by the state.
The oil and gas industry is not among the industries required to file Toxic Release
Inventories under the federal Emergency Planning and Community Right-to-Know
Act. As noted above, Maryland regulation COMAR 26.19.01.02 requires that leaks
and spills be reported. Other laws, federal and state, require the reporting of oil
spills and spills of hazardous materials.
9. There should be a sharing and coordination of emergency management drills by
the Maryland environmental agencies with their counterparts in Pennsylvania and
West Virginia.
As noted above, emergency response personnel at MDE have initiated discussions
with county personnel to explore the possibility of regional response capability so
that response time can be shortened and resources shared. Some coordination
already exists, and was evident in the response to the overturned propane tank truck
in Oakland in April 2014.
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ENFORCEMENT AND INSPECTIONS
Consequences, penalties, fines.
1. The BMPs do not mention fines or punishments when regulations are broken and
local citizens incur damages.
Current regulations, COMAR 26.19.01.15 provide that the Department of the
Environment may, in the event of a violation, issue an administrative order requiring
necessary corrective action, including stopwork, or restoration to be taken within the
time prescribed. These regulations also authorize the Department to revoke a permit,
after notice and an opportunity to request a hearing, if the Department determines
that:
(1) The permittee has failed to comply with the requirements of an
administrative order;
(2) False or inaccurate information was contained in the application for
the permit;
(3) Conditions or requirements of the permit have been or are about to be
violated;
(4) Substantial deviation from plans, specifications, or requirements has
occurred;
(5) The permittee has failed to allow an authorized representative of the
Department upon presentation of proper credentials to:
(a) Enter at any reasonable time upon the permittee's premises where
pertinent operations are conducted, or where records are required
to be kept under terms and conditions of the permit;
(b) Have access to and copy any records required to be kept under
terms and conditions of the permit;
(c) Inspect facilities to ensure compliance with the conditions of the
permit;
(d) Inspect any monitoring equipment or method required in the
permit; or
(6) A change in conditions exists that requires temporary or permanent
modification or elimination of the permitted operation.
Existing State laws and regulations do not provide any administrative or civil
penalties for violations of the regulations or permits. These enforcement options are
valuable and MDE will consider asking the legislature to provide them.
Under Section 14-118 of the Environment Article, the Department can ask the circuit
court of the county where the well is located to issue an injunction to enforce
compliance or restrain the violation of any law or regulation in the oil and gas
subtitle.
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Section 14-120 of the Environment Article provides that any person who willfully
violates any provision of subtitle 14 is guilty of a misdemeanor and upon conviction
in a court of competent jurisdiction is subject to a fine of: (1) Up to $ 50,000; and (2)
An amount sufficient to cover the cost of damages resulting from all of the following
caused by the permittee, including a contractor of the permittee: (i) Any oil or gas
spill; (ii) Any other discharge; and (iii) Any violation of this subtitle; and (3) Costs
imposed in the discretion of the court.
In 2012, the legislature passed a law that makes it easier for a person whose water
supply has been contaminated to compel the owner or operator of a gas will within
2500 feet to provide an alternative source of water. Section 14-110.1 of the
Environment Article. If the contamination is within a year of gas well activity, the
company would have to prove that it had not caused the contamination. After a year,
or beyond 2500 feet, the person whose water supply has been contaminated would
have to prove that the company caused the damage.
2. I think that companies with bad records in other states should be banned from
Maryland.
Section 14-108 of the Environment Article directs the Department to deny a permit
application if the applicant has not corrected any violations committed by the
applicant under any prior permit. Each application must be judged on its own merits.
The Departments also encourage property owners to consider the reputation of a
company before signing a lease for mineral rights. There are internet resources
available whereby citizens can access independent evaluations of oil and gas
company environmental performance and disclosure.
3. The coal strip mining rules in Maryland contain provisions that I think should be
included in Marcellus drilling regulations. In particular when there are cases
where a person’s water source or other property is damaged by gas production,
the State should have the authority to compel the offending party to make proper
restitution or replacement.
There are provisions in Sections 15-516, 15-524 and 15-608 of the Environment
Article that require operators of surface coal mines and deep coal mines to replace
the water supply of a property owner if the supply has been contaminated, interrupted
or diminished. The Bituminous Coal Open Pit Mining Reclamation Fund and the
Deep Mining Fund provide a reserve that can be used for this purpose under certain
circumstances; for example, if the bonds have been released and the mine is closed.
A similar liability provision was enacted in 2012 and codified as Section 14-110.1 of
the Environment Article. This, combined with increased bonding and insurance
provisions passed in 2013 and codified as Section 14-111 of the Environment Article,
protect those in the community. In 2014, Senator Edwards introduced SB535, a
severance tax bill that would have directed money into the Oil and Gas Fund. This
Fund can be used for purposes similar to the coal mine funds. The bill did not pass.
4. Any intimidation or bribes on the part of the shale fracking/drilling companies or
their subsidiaries will result in a direct cancellation of permits immediately and in
the future. In addition, steep fines will be placed on the shale fracking/drilling
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company, along with possible incarceration of any and all parties involved in the
intimidation or bribe.
Bribery of a public official is a criminal offense. Section 9-201 of the Criminal Law
Article. Furthermore, Standards Of Conduct For Executive Branch Employees
established by Executive Order (01.01.2007.01) state that “an employee shall not,
except as permitted by applicable law or regulation, solicit or accept any gift or other
item of monetary value from any person or entity seeking official action from, doing
business with, or conducting activities regulated by the employee's agency, or whose
interests may be substantially affected by the performance or nonperformance of the
employee's duties.” Employees found to violate these provisions are subject to
disciplinary action, including termination from state employment.
Permits can be revoked for cause. Current regulations provide that a permit may be
revoked after notice to the permittee, if the Department determines that:
(1) The permittee has failed to comply with the requirements of an administrative
order;
(2) False or inaccurate information was contained in the application for the
permit;
(3) Conditions or requirements of the permit have been or are about to be
violated;
(4) Substantial deviation from plans, specifications, or requirements has
occurred;
(5) The permittee has failed to allow an authorized representative of the
Department upon presentation of proper credentials to:
(a) Enter at any reasonable time upon the permittee's premises where
pertinent operations are conducted, or where records are required to be
kept under terms and conditions of the permit;
(b) Have access to and copy any records required to be kept under terms
and conditions of the permit;
(c) Inspect facilities to ensure compliance with the conditions of the
permit;
(d) Inspect any monitoring equipment or method required in the permit; or
(6) A change in conditions exists that requires temporary or permanent
modification or elimination of the permitted operation.
Processes must be open and unbiased.
1. All companies performing any monitoring or assessment should be approved by
the State to ensure that no conflict of interest exists which could call into question
the accuracy of the results.
The Department of the Environment does not “approve” environmental, engineering
or consulting firms that do business in the State. However, any monitoring plans
required as a permit condition are subject to departmental approval. These plans
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address quality assurance of the data. The Department reviews monitoring and
assessment data submitted. Finally, Departmental staff must be provided access to
permitted sites at any time for appropriate inspections to ensure permit requirement
are being properly implemented. Any data or information indicating violation of
permit limits or conditions may be grounds for enforcement action.
2. The applicant should not be allowed to do its own baseline monitoring. Either the
State should do the monitoring (using permit fees) itself or the company should be
required to use an independent entity, chosen or accredited by the State, and
subject to oversight similar to the way the Food and Drug Administration
monitors foods and drugs to ensure the reliability of the testing results.
It would not be an efficient use of State resources for the Department of the
Environment to perform the baseline monitoring without compensation from the
applicant or funding provided by permit fees. In some cases, it would not be practical
to use State personnel to perform monitoring, even if funding were available. For
surface water monitoring, however, which involves detailed technical procedures for
biological assessment, the Department of Natural Resources would prefer to provide
the monitoring services. Using DNR monitoring services will reduce the need for
costly quality assurance and control review at the State’s expense and will likely
require fewer resources compared to using a private consulting firm. As noted
above, the Department of the Environment does not accredit companies that operate
in Maryland or require applicants to use a specific company. However, DNR states a
preference for using companies that have been certified for Maryland Biological
Stream Survey (MBSS) monitoring techniques. The work plan for baseline
monitoring will be approved by the State in advance and the data submitted will be
reviewed and checked for quality assurance and quality control.
3. Landowners should have easy access to information about violations. The design
of reports and records are important and can help streamline enforcement
activities. Digital records help share information with the many stakeholders
involved in this process.
The Department of the Environment issues annual enforcement and compliance
reports that cover enforcement activities for each of MDE’s regulatory programs.
MDE also issues regular press releases regarding the most recent enforcement
actions by Administration. These items are available on MDE’s Web site at
http://mde.maryland.gov/aboutmde/DepartmentalReports/Pages/aboutmde/enfcomp.a
spx.
4. Each well site will have one or more continuous air monitoring systems in
operation either in real time or at reasonably short intervals during the lifetime of
the operation of the well. The monitors must be able to trigger alarms at the well
site and at a remote monitoring site that is staffed 24/7 when established pollutant
levels are exceeded. Ideally all toxic chemicals used in the drilling and any
expected to be in effluents from the wells should be monitored as well as fugitive
methane. After eventual capping of the well periodic monitoring at the site should
continue to be conducted.
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The Department of Environment investigated the question of ambient air monitoring
at well sites. Ambient air monitoring is not justified on a continuous basis for every
well, nor would it be practical. The Department is considering monitoring and leak
detection and will include appropriate requirements in individual permits.
5. I suggest Maryland require 24 hour video surveillance of all well pads to allow
remote monitoring and inspection and provide verifiable data in the event of
incidents. This is especially important if Maryland adopts its recommendation that
specially trained and equipped personnel must be capable of arriving at the site
within 24 hours of the incident.
Even if video surveillance were required, practical constraints would mean that the
video would not be reviewed unless an incident was reported. Accordingly, the
Departments agree that an important best management practice is the requirement
that drilling companies establish emergency response plans to include a mechanism
for notifying local jurisdictions promptly regarding chemical spills or releases.
During drilling and hydraulic fracturing, the operations are staffed 24/7 by the
permittee. Incidents that occur during these times, and times when workers are on
site to work on the well or perform maintenance, will be immediately known.
Incidents at wells that are operating but unattended can often be detected by the
company’s own remote monitoring systems. The written communications plan that
applicants for permits are required to develop will assure that the information is
promptly communicated to the proper authorities. The type of incident that requires
specially trained and equipped personnel, such as a well blowout or fire, would
probably be immediately evident. Local residents are also encouraged to notify local
authorities or the Department of the Environment if spills or other emergencies are
witnessed.
6. There should be a clear mechanism for citizens to report violations of the law or
of permits or lodge complaints.
The Departments agree that there should be a simple way for citizens to report
suspected violations of the law or permits. MDE staff are always on call during the
regular workweek and on weekends, holidays and after normal working hours, to
ensure that all environmental emergencies are promptly addressed. You may report
any environmental emergency that poses an immediate threat to the public health or
the well-being of the environment such as oil and chemical spills or accidents causing
releases of pollutants by calling toll free (866) 633-4686. Anonymous calls are
accepted.
Non-emergency environmental concerns should be directed to the relevant program
at MDE. The oil and gas program can be contacted during business hours at 866MDE GOTO which is (866) 633-4686.
Permittees will be required to post contact information at the entrance to the site.
Complaints that are not about violations should be communicated to the permittee.
7. The protocols for monitoring, recordkeeping and reporting should be submitted
for public comment. It should be clear about testing of water wells – who will
test, what they will test for, and how the tests should be conducted.
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The Department of the Environment will provide guidance for monitoring,
recordkeeping and reporting. Some will be in regulation, which will be subject to
public notice and comment. The monitoring plans themselves will be submitted with
the permit application and will be available for public review and comment.
8. There should be a sharing and coordination of environmental monitoring data by
the Maryland environmental agencies with their counterparts in Pennsylvania and
West Virginia.
The Department of the Environment participates in interstate compacts and attends
regional meetings where information is shared. The Department also maintains
communication with regulatory agencies in other states through conferences
organized by the National Governors Association, the Environmental Council of the
States, and EPA. Furthermore, in developing Maryland’s draft best management
practices and other related recommendations and requirements, the Departments
have reviewed incident and other environmental data in neighboring states and
throughout the country to ensure the best practices for environmental protection are
adopted.
State resources may be inadequate.
1. Conducting inspection and enforcement activities is challenging due to limited
information, such as data on groundwater quality prior to drilling. Hiring and
retaining staff and educating the public are challenges. I have great concern about
the availability of qualified individuals to perform these functions.
Site-specific background data will be collected for each site. The Departments are
aware of the challenges of hiring and retaining qualified personnel. The Department
of the Environment’s future adoption of permit fees will help with hiring additional
personnel to assist with inspections and enforcement.
2. Money for state inspectors and independent inspectors should come from higher
permit fees, not tax payer dollars. In the strongest possible way, I want to
emphasize that the resources to pay for regulators, monitors and enforcers of such
vital functions as water quality, air quality and noise monitoring should be borne
by the drilling companies.
The Department of the Environment is authorized to set application and permit fees
for oil and gas wells at a level to operate the regulatory program, including
monitoring and enforcement.
New programs are needed.
1. A new regulatory agency is necessary.
a.
A “designated agency” would be set up and maintained through the
county or state government for permit issuance, reporting purposes,
inspections, and legal action. All of which would be considered a
reimbursable fee to the shale fracking/drilling companies reimbursed
on a monthly basis.
b.
Any illnesses resulting from the shale fracking/drilling companies for
families, and employees of the shale fracking/drilling company, must
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be reported to the “designated agency.” All information regarding
hazards, illnesses, contamination, road spills, etc. will be a part of
public record and maintained by the “designated agency”.
c.
Inspectors are to be hired by our county or state government, though
the “designated agency” and the funds to pay for their salaries and
benefits are to be reimbursed by the shale fracking/drilling companies
on a monthly basis through an invoice provided by the “designated
agency.” This also includes any fees incurred, such as mileage,
maintaining an office, etc. The shale fracking/drilling companies may
not be or hire their own inspectors to report to the permitting
“designated agency”.
d.
All chemicals that are to be used must be submitted to the “designated
agency” prior to permit issuance. These chemicals cannot include
contaminates that would affect any aquifers, rivers, wells, or public
drinking water or cause cancers or illnesses. All of these chemicals
will be a matter of public record. Inspectors will test the chemicals on
a bi-monthly basis to ensure hazardous chemicals are not being used
by the shale fracking/drilling companies.
e.
All clean-up will be provided by the fracking/gas drilling company
within 3 months of vacating any site. In addition, the shale
fracking/drilling company will be held completely responsible for
expenses relating to the clean-up and maintenance of any capped well
that may later leak after being closed, as well as any other issues
resulting from this leak. There will be no time limit on this
maintenance. A designated trust fund is to be set aside to cover these
expenses and is to be used only for the purpose of maintaining closed
wells. This amount will be provided by the “designated agency.”
Many of the tasks the commenter wishes to assign to a new designated agency are
already within the responsibility of existing state agencies. Likewise, permit fees will
be established and paid by industry to help support regulatory oversight activities.
The substantive concerns expressed by the commenter regarding chemicals and
clean-up are addressed in Departmental responses to chemicals and emergency
response-related comments.
2. There should be clearly identified state agency points-of contacts, processes, open
damage claim reporting and detailed restitution when issues arise. There should
be a mechanism to fairly compensate people for economic loss and personal
harm, especially people who did not lease their mineral rights but are impacted by
gas development nearby. The State should consider denying a CGDP permit if
any landowner within the CGDP does not own his mineral rights (i.e. a split
estate).
The commenter may be envisioning something like the court-supervised settlement
program that was instituted after the Deep Water Horizon well blowout in the Gulf of
Mexico. The settlement followed two class action lawsuits and set up a procedure
and fund to compensate people for economic and property damage claims and
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medical claims. Such programs are not developed in advance, on the chance that an
incident will occur.
The court system provides an avenue for individuals to seek compensation for injury
or damage caused by willful misconduct, negligence, trespass, nuisance and
contamination. The Department of the Environment can order a permittee to cease a
violation and remediate spills, but there are issues of due process, property rights
and contract rights that preclude a State agency from circumventing the legal process
and awarding damages.
3. We want the State to secure and fund an external independent environmental
consulting and auditing entity or capability (firm) to perform daily independent
inspection of all on-the-ground drilling activities to ensure full compliance of all
regulations. This firm will host bi-monthly or monthly public meetings to address
current concerns and complaints with local stakeholders. Oversight of this firm
will be provided by a small Board of Directors composed of local civic leaders.
And lastly, that "drilling fees" be established by MDE with a line-item breakdown
of drilling fees and what they include so that it is possible to ensure that adequate
funds for inspection and enforcement is possible.
This firm will fill the following roles:
1. insure that the enforcement and inspection function is adequately funded,
well managed and staffed with qualified personnel;
2. promote transparency via bi-monthly or monthly public meetings to
address issues in a timely manner;
3. protect the enforcement and inspection function from political and energy
sector intimidation or influence;
4. perform ongoing auditing and reporting functions to track the
effectiveness of regulatory enforcement practices; and provide an external
source of objective expertise relating to drilling practices.
See response to comment 1 “A new regulatory agency is necessary”. The
Department of the Environment has the authority to assess application and permit
fees for oil and gas wells in amounts sufficient to fully fund its program, including
inspection and enforcement. The Departments take their missions very seriously and
are guided by science. Intimidation is not an issue. MDE prepares an annual
enforcement report on all its programs.
4. There is a strong need for a Comprehensive Gas Drilling Inspection Program
(CGDIP) that would:
1. Require special training for inspectors in Maryland to follow for
inspection compliance,
2. Show all phases of development and the inspections for each phase,
3. Allow for random visits and spot inspections
4. Mandate compliance with each phase for work to continue,
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5. Establish a community/citizen watch program, that would train individuals
on how to report incidents and/or violations,
6. Establish a Natural Gas hot line for reporting,
7. Mandate the number of inspectors in relationship to the number of
permits,
8. Establish a sliding scale penalty for repeat violations,
9. Establish a three strikes and out program that would keep repeat violators
from receiving permits,
10. Establish an Ombudsman commission for review of complaints and
compliance issues,
11. Establish a website for licensure, permitting and inspection, which would
include public notification of CGDP planning and permitting. This site
could also be used for the CGDP Toolbox,
12. Establish a field office of the Natural Gas division of MDE/DNR in
Garrett County.
If inspectors need additional training, MDE will secure that training and recover the
cost through application and permit fees. If the intensity of gas development justifies
it, MDE will locate trained inspectors in a western Maryland office. Unannounced
inspections are already a part of MDE’s inspection process. There is an existing
method by which citizens can report incidents and suspected violations. An
individual may report any environmental emergency that poses an immediate threat
to the public health or the well-being of the environment such as oil and chemical
spills or accidents causing releases of pollutants by calling toll free (866) 633-4686.
Anonymous calls are accepted. Non-emergency environmental concerns should be
directed to the relevant program at MDE. The oil and gas program can be contacted
during business hours at 866-MDE-GOTO, which is (866) 633-4686. On-site
inspections by citizens are inadvisable due to security and safety concerns, as well as
issues of trespass.
The Departments are committed to openness and transparency and will make efforts
to provide all necessary information on its website. Compliance issues should be
handled through the MDE’s established inspection and enforcement program. The
idea of an ombudsman has merit and could be considered if companies are not
responsive to citizen concerns.
Existing State laws and regulations do not provide any administrative or civil
penalties for violations of the regulations or permits. These enforcement options are
valuable and the Department of the Environment will consider asking the legislature
to provide them. Appropriate penalty amounts for second and subsequent violations
could be incorporated.
A “three strikes” rule is not appropriate because the types of violations range from
minor to serious. Each application will be considered on its merits.
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5. The collection of pre-development baseline data is good, but the same kind of
data should be required during the production and for at least 3 to 5 decades after
decommissioning and capping.
Periodic monitoring will be required while the well is in production, but at this time
the Departments are unaware of any justification for monitoring for decades after the
well has been properly abandoned and the site reclaimed. Post-closure requirements
can be reevaluated and adjusted if there is a reason to require additional monitoring.
6. All storage containers and transportation vehicles that handle wastewater,
flowback, drilling muds, cuttings, fuel and chemicals should have GPS tracking,
placards and radioactive monitors.
The draft best practices report recommended that applicants submit a transportation
plan and a waste management plan for approval. In order to assure that all wastes
and wastewater are properly treated or disposed of, the Departments proposed to
require permittees to keep a record of the volumes of wastes and wastewater
generated on-site, the amount treated or recycled on-site, a record of each shipment
off-site and a confirmation that the waste was received at the designated facility. In
the draft report, the Departments proposed to “Require that all trucks, tankers and
dump trucks transporting liquid or solid wastes be fitted with GPS tracking systems to
help adjust transportation plans and identify responsible parties in the case of
accidents/spills.” There was wide support for the GPS requirement, but the
Maryland Motor Truck Association commented that this requirement “is virtually
impossible in an industry that is deregulated, highly fragmented, and uses a large
number of independent contractors to meet short-term transportation needs.” The
permittees and operators are in a position to require its contractors and
subcontractors to use GPS equipment, despite the fragmentation of the industry.
The transportation of hazardous materials is regulated by the United States
Department of Transportation, which requires placards for shipments of hazardous
chemicals above threshold amounts. For example, a truck would have to display a
corrosive placard if it carried a material that met the definition: “a liquid or solid
that causes full thickness destruction of human skin at the site of contact within a
specified period of time. A liquid, or a solid which may become liquid during
transportation, that has a severe corrosion rate on steel or aluminum based on the
criteria in §173.137(c)(2) is also a corrosive material....” 49 CFR 173.136(a).
Lastly, the Departments proposed that cuttings, flowback, residue from treatment of
flowback and produced water, and any equipment where scaling or sludge is likely to
occur shall be tested for radioactivity and disposed of in accordance with law.
7. While there is Federal regulation of new construction of pipelines with the
attendant compressor stations, no State agency exists to oversee the siting,
construction and operation of these assets.
The Pipeline and Hazardous Materials Safety Administration of the United States
Department of Transportation has established standards for the material, design,
construction, and testing of pipelines that carry natural gas. The Federal Energy
Regulatory Commission (FERC) authorizes interstate pipelines, including
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compressor stations that are part of interstate pipelines. Intrastate pipelines,
including compressor stations that are part of intrastate pipelines, are overseen by
the Maryland Public Service Commission (PSC). FERC approves the siting of
proposed routes for interstate pipelines and associated facilities. Intrastate lines do
not have to come to the FERC or the PSC for approval of their routes. Their routes
are developed through agreements with landowners for the right‐of‐way. They do
have to get approval from other State agencies for such things as air permits and
stream crossing permits. The PSC has the authority to inspect gathering lines and
intrastate pipelines.
The Comprehensive Gas Development Plan will help coordinate the siting of drill
pads, gathering lines, compressors, and other ancillary facilities.
8. Currently, federal oversight of pipelines in Maryland is inadequate. To expand
the number of pipelines by authorizing increased production via well permitting
while the regulatory system is already struggling under current conditions would
only increase the likelihood of accidents or failures.
The safety of interstate gathering lines, transmission lines, compressor stations and
storage facilities is regulated by the U.S. Department of Transportation’s Pipeline
and Hazardous Materials Safety Administration (PHMSA). The Maryland Public
Service Commission (PSC) regulates these facilities when they are classified as
intrastate, and the PSC also regulates distribution systems. If drilling is permitted,
there will certainly be more intrastate pipeline development. The capacity to manage
these additional needs will be expanded if required.
9. Post-operational sampling of air quality should be required for ancillary facilities,
such as compressor stations, that have the potential to emit gases.
The Departments will require monitoring of ancillary facilities such as compressor
stations in air permits, if justified.
Financial liability for monitoring and harm.
1. Companies permitted to conduct a fracking operation in Maryland should be
required to post a bond sufficient to cover penalties for any violations that might
occur in the course of their work, regardless of any showing of negligence on
their part. These penalties need to be sufficient to cover the costs of restoring the
environment to a safe and livable condition.
Financial assurance and bonding requirements in Section 14-111 of the Environment
Article address these concerns.
2. All legal fees acquired by a landowner, affected party, or the government will be
reimbursed by the shale fracking/drilling companies for any reason.
The general rule in America is that each party to a suit pays its own attorney’s fees.
Court costs are usually paid by the losing party.
3. There should be adequate bonding and insurance requirements, lasting beyond the
closure of the well. Bonds for delayed contamination caused by triggering hydrogeo-mechanical events should be added, such as the inevitable upward migration
of enhanced vertical permeability.
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The Departments do not agree that contamination is likely to be caused by upward
migration due to hydraulic fracturing. Bonds are released only after closure is
complete. Environmental Impairment Liability insurance must be secured and
maintained for 5 years after the Department determines that: (1) The gas or oil well
has been properly sealed and plugged; and (2) The site has been reclaimed.
4. Demand that companies engaged in fracking are financially liable for any and all
costs incurred by residents including health expenses, soil contamination, legal
fees, loss of property values and reduced quality of life during and after the
operation.
Financial assurance and insurance will guarantee that funds will be available if the
companies engaged in hydraulic fracturing are liable for damages.
5. Any and all hazards, such as well contamination, explosions, death, crop
destruction/contamination, hazardous fuel transportation accidents, business loss,
etc. that are directly associated with fracking/drilling will be paid for by the
company. This includes, but is not limited to emergency personnel costs, funeral
costs, loss of income, land devaluation, legal fees, injuries, and any costs
associated with the hazard.
See responses to comments 1-4.
6. There should be an explanation of what the State would do, or compel the
company to do, if gas were to flow from somewhere in the gas field into a
person’s home or into the atmosphere. What are the requirements for restoration
of trout streams should fluids pollute the water? What types of restitution should
citizens expect if their property and or health is negatively impacted, or are locals
expected to work with the oil & gas firm directly? A process must be developed
to deal with and assign responsibility for unexpected problems especially if more
than one industry operator is working in the same area.
Current regulation COMAR 26.19.01.15 provides that the Department of the
Environment may, in the event of a violation, issue an administrative order requiring
necessary corrective action, including restoration, to be taken within the time
prescribed. The specific instance of contamination of drinking water within 2500 feet
is addressed in Section 14-110.1 of the Environment Article. There are existing
liability and pollution insurance requirements in §14–111of the Environment Article.
Also a bill introduced by Senator Edwards in the 2014 session, SB 535, would
provide funds and authorize the Department to take corrective action if the persons
responsible for the harm could not be identified or were bankrupt or otherwise
judgment proof. This legislation did not pass.
7. We believe that liability of water well contamination within 2500 feet of a drilled
gas well must be incorporated into the permitting process and the time period
extended beyond one year of the drilling activity to ensure water quality and
public health are protected.
Persons with drinking water wells within 2500 feet from the gas well or whose wells
are contaminated within a year after the last event of well drilling, completion, or
hydraulic fracturing can take advantage of the presumption established in Section 14-
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110.1 of the Environment Article. After one year, the person whose drinking water
was affected would have the burden of proving that the gas company was liable. If
gas activity is permitted, monitoring results or new research might justify extending
the time period for this presumption.
ENGINEERING, DESIGN AND ENVIRONMENTAL CONTROLS AND STANDARDS
Ponds.
1. Ponds should be used only to collect or store fresh water; all other material shall
be stored in tanks.
2. We support the proposed prohibition on open impoundments for the storage of
flowback and produced waters as a necessary safeguard. Open impoundments
create unnecessary risks of wildlife exposure to chemical‐laden fluids and
environmental damages from impoundment spills. MDE and MDNR have laid out
an appropriate approach, allowing open impoundments to be used only for fresh
water storage.
3. The state needs to coordinate closely with the local municipalities on construction
standards for ponds.
The Departments agree that ponds should be used for fresh water only, and that
flowback and produced water should be stored in tanks while on-site. This was a
recommendation in the draft report. The regulations will also specify that the tank
system has sufficient structural integrity and is appropriate for the storing of the
intended wastes, including compatibility with the wastes.
Ponds must conform to USDA Natural Resources Conservation Service Maryland
Conservation Practice Standard Pond Code 378 (January 2000). The standard
establishes the minimum acceptable quality for the design and construction of most
ponds.
Casing, cement, and centralizers.
1. The use of reconditioned casing should not be permitted.
The Departments do not agree. It is appropriate to use reconditioned casing if it
meets API performance standards for compression, tension, collapse and burst
resistance, as well as quality and consistency.
2. The specified safety margin of 1.2 for reconditioned casing seems small; a factor
of 2.0 is viewed as more common.
The draft report recommended that reconditioned casing may be permanently set in a
well only after it has passed a hydrostatic pressure test with an applied pressure at
least 1.2 times the maximum internal pressure to which the casing may be subjected,
based upon known or anticipated subsurface pressure, or pressure that may be
applied during stimulation, whichever is greater, and assuming no external pressure.
The proposed recommendation is based upon API Standard 5CT, Specification for
Casing and Tubing, and the Departments consider it appropriate.
3. How did the Departments determine that pilots can be “safely cased through” coal
mines?
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The Departments recognize the inherent danger in drilling through coal mine areas.
A pilot hole would be a small diameter hole drilled to provide more site-specific
knowledge of the subsurface geology. Coal seams would only be present in the first
several hundred feet from surface and the pilot could provide valuable information
for the development of the actual casing and cementing plan for a production well.
The pilot would be similar to a coring that is presently done to define geology in
preparation for a coal mine permit. The judgment that holes can be safely cased is
based on experience. In comments, the Board of Directors and committee members
of the Casselman Coal Poolee Association endorsed this recommendation.
4. Requiring the cement to remain in a static state for a minimum of 12 hours and to
achieve a compressive strength of 500 psi is excessive. Modern cement additives
and slurry designs can achieve the 500 psi requirement in much less time than 12
hours. It is recommended the recommendation be changed to allow for
continuation of activities if the cement has reached a minimum of 500 psi.
The Departments recognize that the 12 hour set time will cause some delay in
drilling. The Departments also believe that the proper setting of the cement is one of
the most critical tasks in the safe drilling process. The Departments therefore do not
accept the suggested change.
5. For cementing, centralization, and wellbore isolation, it is suggested the
recommendation incorporate API Standard 65-2, “Isolating Potential Flow Zones
During Construction” in the document. This standard contains design and
engineering practices for isolation of potential flow zones and goes beyond the
limited recommendations found in the current document. API Standard 65-2 has
been adopted into both federal and state regulations and serves as an industry
guidance document for proper well design and construction.
API Standard 65-2 would qualify as a “relevant API standard.” The best practice
report requires that the applicant for a well permit file a plan that follows the
normative elements of relevant API standards, or demonstrate that an alternative is
at least as protective.
6. The recommendation is all coupling threads meet the API specifications and
casing strings be assembled to the correct torque. This requirement eliminates
proprietary threads that may exceed API specifications and also does not allow for
the use of couplings that are made up to a particular depth rather than a minimum
torque. The recommendation should allow for the use of API threads or threads
that exceed API requirements based on an engineering analysis and judgment.
The Departments agree and will amend the recommendation to provide that the
applicant can, when submitting the plan for a well, make an engineering
demonstration that an alternative is at least equally protective.
7. There is a recommendation that the operators “must use a sufficient number of
centralizers to properly center the casing in each borehole.” There is no definition
of what degree of centralization is required, the allowable type of centralizers, or
the proposed installation methods. This information can be found in the API
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technical documents, recommended practices, and specifications for centralizers.
It is recommended the recommendation include these documents by reference.
API Standard RP 10D2 regarding use of centralizers would qualify as a “relevant
API standard.” The best practice report requires that the applicant file a plan that
follows the normative elements of relevant API standards, or demonstrate that an
alternative is at least as protective.
8. The State and the MSAC needs to do more to study and address the causes of
casing integrity failure and to propose better practices that continually improve
performance of casing integrity.
The Department of the Environment actively participates in forums and follows
studies conducted by agencies and organizations such as EPA, the Groundwater
Protection Council, the National Governors Council and the Interstate Oil and Gas
Compact Commission. The Departments are also requiring rigorous monitoring
before and during well development to assist in identifying casing/cementing
problems. In addition we will continue to monitor other states and industry
developments.
Additives, closed loop systems for drilling mud and cuttings.
1. Our organization supports the Report’s recommendation in Section VI part H that
“Diesel fuel shall not be used in hydraulic fracturing fluids.”
The use of diesel fuel in hydraulic fracturing has been the subject of concern in
several contamination investigations. The Departments do not propose to allow its
use in hydraulic fracturing in Maryland.
2. Closed loop mud systems are commonly used where non-aqueous drilling fluids
are used. There may be unintended consequences of requiring closed loop mud
systems for all drill sites. A closed loop system will add costs to the drilling
operation and will require additional space on the drilling pad to incorporate the
technology. To allow for spotting the needed tanks for the process can require up
to 6 acres for the drill site. This increases the surface footprint of the drilling pad
above what would be required for non-closed loop systems.
The Departments believe that the benefits of the closed loop system in managing and
disposal of cuttings and waste drilling fluids exceed the temporary impact of land
disturbance for the tanks and structures needed. The Departments note that at least a
portion of that disturbance will be offset by not constructing pits for storage.
3. How will the Department determine whether to approve additives for drilling
fluids?
As mentioned in the draft report, only additives suitable for drilling through potable
water can be used for at least 100 ft below fresh water or coal seams. For drilling
below that depth the Department of the Environment will consider the constituents of
the product, the concentrations to be used, and information on toxicity and health
effects from the Material Safety Data Sheets.
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Pad construction and containment.
1. “Permeability” is the wrong word in the sentence: “Drill pads must be underlain
with a synthetic liner with a maximum permeability of 10-7 centimeters per
second …”
The commenter is correct; “permeability” will be replaced by “hydraulic
conductivity.”
2. Containment around tanks and containers should be underlain with a synthetic
liner with a maximum permeability of 10-7 centimeters per second to prevent
leaching into the soil.
The Departments anticipate that many tanks and containers will be located on the
pad, where the liner must have a maximum hydraulic conductivity of 10-7. Secondary
containment is required for all stored chemicals and wastewater, but this low
hydraulic conductivity may not be necessary in all circumstances. The Spill
Prevention Control and Countermeasures Plan must address the prevention and
clean up of spills.
3. The berm should be made impermeable with the use of the liner. In the event of a
high volume, high pressure liquid release an earthen dam will likely fail and use
of a liner would prevent or minimize a failure.
The best practices report recommended that the drill pad must be surrounded by an
impermeable berm. This may be accomplished by using natural materials or a liner.
The applicant must submit a plan for constructing the pad and containment structures
with the application for a well permit.
Integrity testing and BOP.
1. Use of data obtained through open hole logging to “fine tune” processes and
information (as recommended by UMCES-AL) should not be considered
sufficient stand-alone information in the absence of a complete study of
hydrology of the site. We should not be drilling blind in Maryland and using the
drilling process to document the strata.
The UMCES-AL report stated, in the context of discussing different well logging
techniques, that “The best practice would utilize modern open-hole well logging
methods to help fine tune casing placement and characterize flow and hydrocarbon
zones, perhaps mud logging to determine levels of hydrocarbons in real-time during
drilling, and SRCBL, casing collar logging, and gamma logging as part of a casedhole program.” The use of open hole logging is intended to supplement data already
available and to be used in the permit review process. Any site specific data will be
valuable to subsequent well placement and technique. All available hydrologic data
such as existing water or other wells, previous excavations and all geologic/seismic
data will be evaluated in the individual permit process.
2. Due to concerns about casing integrity discussed above, the plan for integrity and
pressure testing submitted by applicants for individual well permits should
include integrity tests not only at drilling and re-fracturing, but also at annual
intervals until the well is plugged, and at regular intervals going forward.
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The Departments agree that testing should be performed periodically during the
lifetime of the well. The specific types of tests and frequency of tests will be an issue
addressed in each permit and based upon the documented pressures at each
individual well. The Departments are not aware of justification for integrity testing
after the well is plugged.
3. Rather than specifying that blow out preventers should be tested at a pressure in
excess of that which may be expected at the production casing point before
drilling the plug on the surface casing; and penetrating the target formation, the
regulations needs to specify that blow out preventers the pressure to be 1.2 times
the pressure during stimulation, which is the highest pressure normally
experienced during the life of the blowout preventer.
The regulations will be clarified to provide that the blow out preventers must be
tested at a pressure at least 1.2 times the highest pressure normally experienced
during the life of the blow out preventer. The regulation will likely closely conform to
API RP 53.
4. The regulations recommend pressure testing of Marcellus shale gas wells. That
isn't sufficient. The BMP practice recommended in the UMCES report to require
pressure testing should instead be adopted. Doing so would greatly increase the
likelihood that all wells would function as they should.
See response to question 2 above regarding increased frequency of
integrity/pressure testing. Moreover, in the draft best practices report, the
Departments wrote: “The UMCES-AL report recommended Maryland should
consider amending its regulations to require SRCBL (or equivalent casing integrity
testing) and other types of logging (i.e., neutron logging) as part of a cased-hole
program. The Departments agree and propose to require SRCBL.” In addition, the
Departments will require mechanical integrity tests to be performed when refracturing an existing well.
Noise, light and hours of operation.
1. The best practices report notes that if drill pads are located within 1,000 feet of
aquatic habitat, screens or restrictions on the hours of operation may be required
to further reduce light pollution. Additional light sensitive uses include
residential units, educational facilities, hospitals, critical facilities and agricultural
uses including livestock. Maryland should consider developing light standards
for pre and post curfew time periods when sensitive land uses are near-by.
The Departments agree that there are many sensitive land uses that could be
affected by drill pad lighting. These issues will be considered in the CGDP and
addressed on a case-by-case basis during the individual well permitting and
associated public participation process, taking into account the nearby sensitive
land uses and stakeholder concerns.
2. The report says that restrictions on hours of operation can only be applied to
activities that could be planned in advance or temporarily suspended. This
statement gives the industry an escape clause to use lighting at any time during
development activities. It should be strengthened to say, in the last sentence: For
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this reason, activities should be planned in advance so that all measures can be in
place to protect surrounding communities from light pollution.
Advance planning and the selection of proper lighting can minimize the effect of
lighting, but lighting is a safety issue.
3. Light pollution as well as noise pollution should be addressed because light
pollution corrupts the wildlife cycles and destroys the sense of solitude for
residents and tourists.
The Departments agree and this is why both light and noise pollution will be
considered at multiple stages of the gas well development process, from the CDGP
process all the way through issuance of individual permits.
4. Ban flaring during hours of darkness, and also ban lighting that destroys the
night sky.
The Departments have proposed restrictions on flaring and lighting that protect the
public and do not compromise the safety of workers. The Departments propose that
night lighting be used only when necessary, directed downward, and that low
pressure sodium light sources be used wherever possible.
5. The recommendation that drilling should avoid times of peak outdoor recreational
periods is unreasonably restrictive.
This recommendation is not only for aesthetic purposes but also to ensure public
safety. Consideration will be given in individual well permits to the proximity of the
well to peak recreational uses.
6. The recommendation about lighting should state that nothing in this section
should be construed to compromise safety of operation at the drilling site.
Safety at the drill site is essential to prevent harm to workers, the environment and
public health. The manner in which lighting is addressed at each well pad will not
compromise safety of operations.
Standards and updating standards.
1. There is a long list of plans and information that must be submitted with an
application for a drilling permit. Will regulations provide “standards” for most
of these, or are the approval criteria viewed as inherently case-by-case?
Before a permit will be issued, the applicants are first required to develop a
Comprehensive Gas Development Plan, and guidance is provided in the Best
Practices document to inform that effort. Plans for individual wells must then
conform to the Engineering, Design and Environmental Controls and Standards.
Relevant API standards must be considered and, if the applicant fails to incorporate
a normative element of a relevant API standard, the plan must explain why and
demonstrate that the plan is at least as protective as the normative element. All
applications will then be reviewed individually and additional site-specific
conditions may be considered at that time. Regulations will provide guidance as to
what will be expected in the application.
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2. Given the view that mandating particular technology is neither appropriate nor
necessarily productive, the question becomes how the adoption of “better” as
well as more efficient technologies might be motivated. An option for
consideration: require industry to discuss their plan for adoption of “better”
technology as part of the CGDP’s and/or the individual well applications.
One way the Departments will encourage the adoption of better technology is to
require consideration of all relevant API standards. These standards are
periodically updated. To the extent better technologies are developed, they can and
should be considered both in the CGDP and the individual permit.
3. Maryland should adopt the Center for Sustainable Shale Development
performance standards as a baseline. Deviations from those standards, if any,
should be limited to those necessary to reflect conditions that are unique to
Maryland.
The Departments incorporated some of these performance standards into their best
practices report and agree that the standards can be a useful tool for evaluating
whether plans submitted with applications for individual permits are adequate. The
Departments do not think it necessary to adopt those standards as a baseline. If these
standards meet or exceed normative API standards, however, they can be used by
applicants in place of API standards and will be approved by MDE, provided they
meet other applicable regulatory requirements.
Fuels and engines.
1. Engines operating on a site for less than 12 months are federally-defined as
nonroad mobile engines, and Maryland is pre-empted by the Clean Air Act from
imposing any emission standards on those engines.
This is correct. Maryland is preempted from making these federal regulations
applicable to a class of engines that are excluded from the federal regulations. The
recommended best practices will be changed to avoid imposing emission standards
on those engines; however, the State will continue to explore ways to reduce
emissions from nonroad mobile engines.
2. The final report should not mandate the use of electrical powered equipment or
designate a preferred fuel source for engine-powered equipment.
The Departments are not mandating the use of grid-based electrical power or a fuel
source for equipment. There are multiple factors which would favor the use of one
power source or fuel over another, including the land disturbance necessary to bring
power to the site, the greenhouse gas footprint of electricity supplies and the loss of
power resulting from running electrical transmission lines to the drill site. The
Departments recommend that applicants provide a power plan that results in the
lowest practicable impact from the choice of energy source. The recommendation for
using natural gas or propane is a preference, not a requirement.
3. All on-highway and nonroad vehicles are already required to use ultralow-sulfur
diesel fuel, so Section IV.J.4.a should be removed as unnecessary.
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The requirements were fully phased in for most engines by 2014. The provision may
be unnecessary, but there does not seem to be any harm in keeping it.
Roads.
1. Given the levels of traffic and the size of equipment used, even gravel roads will
need to be planned and engineered to be safe. Additional design standards are
needed.
2. Why use Pennsylvania road specification? The State of Maryland has been very
critical of natural gas operation in Pennsylvania. It just seems strange that we
would rely on their standards, especially since Maryland has been so critical of
Pennsylvania's management of Marcellus gas development. Allegany and Garrett
County have standard specification and roads department personnel to review and
approve plans for roads. Let the two counties determine road requirements as they
do for all need development in the counties.
The Departments agree that new roads used by the industry will need to be planned
and engineered. The UMCES-AL report recommended using Pennsylvania’s
“Guidelines for Administering Oil and Gas Activity on State Forest Lands” because
they contain particularly good practices for constructing and maintaining gravel
roads for Marcellus Shale development in Pennsylvania state forests. Since
Pennsylvania already experienced the traffic and associated wear-and-tear on roads
that occurs during gas well development, it has valuable experience in developing
guidelines on proper road design to protect state forests. Furthermore, since much of
the Marcellus underlies Maryland’s heavily forested counties, roads designed to
protect forested landscapes are most appropriate.
Pennsylvania’s guidelines recognize that roads constructed for gas development will
experience repeated use over the life-cycle of well production, must be designed to
withstand heavy, sustained, industrial scale traffic over decades, must protect forest
lands and waterways, and must serve other purposes (utility corridors) in addition to
vehicular access. The guidelines also include other important consideration such as
guideline for emergency and pollution incidents. The Departments view these
guidelines as protective of Maryland’s water quality and natural resources.
The standards for roads are meant to apply only to private roads, such as access
roads, that may be constructed to reach the well pad. Garrett County has
established minimum standards for private roads in its subdivision regulations, but
“road” is defined as “a public or private thoroughfare which affords the principal
means of access to 3 or more lots or that is an expressway, but not including an
alley or a driveway.” Under this definition, the standards would not apply to an
access road. Allegany County reviews the plans for private roads, but has no
construction standards. Both Counties have standards that will apply to the
construction of public roads or roads that will be dedicated to public use. Where
they apply, these standards and not Pennsylvania guidelines will be used.
Invasive species, site closure.
1. The permit should require photographs of the site before the activity starts. This
information will be very helpful for reclamation assessments later on. Because
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mines operate for such a long timeframe, very few people remember what the
conditions were 30 years ago.
The Departments agree with this comment. Permit requirements for a predevelopment site characterization should include photographic records. Site closure
requirements after gas extraction has occurred should also include photographic
records.
2. All clean-up will be provided by the fracking/gas drilling company within 3
months of vacating any site.
Current laws and regulations place the responsibility for site reclamation on the
permittee. Performance is assured through bonding. The time period for when site
reclamation must start after gas well drilling is completed and how long it should
take to complete the reclamation is not spelled out in the BMP document; however, a
reclamation plan must be submitted with the application for a well. This plan and the
invasive species plan must address both interim and final reclamation. An approved
plan becomes part of the permit and therefore is enforceable.
3. All construction of well-pads and associated uses should be prohibited in areas
that are dominated by invasive species.
The Departments agree that construction in areas dominated by invasive species has
the potential to spread those species. The invasive species plan set out in the best
practices report was intended to address the risk that invasive species would be
introduced to the construction area, but it will also serve to prevent the spread of
invasive species from the construction area. For example, the applicant must
perform an inventory survey of sites prior to operations, and the plan must include
procedures for avoiding the transfer of species by clothing, boots, vehicles, and water
transfers including assuring that the water withdrawal equipment is free from
invasive species before use and before it is removed from the withdrawal site.
4. Keeping equipment clean is important for controlling the spread of invasive
species, but it is also important to monitor construction materials such as any soil,
gravel or fill dirt that is brought to the site for construction. If there are existing
invasive species, pre-treatment activities should be required before construction
starts.
The Departments agree with this comment. The invasive species management plan
should emphasize avoidance, early detection and rapid response. The elimination of
existing invasive plants should be considered. For species that do little damage,
control may not be warranted. For large existing infestations, the level of effort
required may be prohibitive and the probability of success very low. However, for
relatively small infestations of extremely damaging invasive plant species, control
can be both cost-effective and successful. We adopted the UMCES-AL
recommendation that topsoil should be stockpiled during site development activities,
covered during storage, and used on site during reclamation. The invasive species
and reclamation plans must address the risk that materials brought on site may bring
invasive species.
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5. Annual monitoring for invasive species should occur at the appropriate time of
year to identify early infestations. Annual monitoring should occur throughout
the entire lease cycle plus one year. Because many plants have seasons, it will be
important to have the last inspection in the growing season after activity has
stopped.
The Departments agree with this comment. These monitoring activities will be
required for each operator’s invasive species management plan that must be
reviewed and approved by MDE before any permits are issued.
6. In some cases, grading and plantings will be needed to return the site to preconstruction conditions. For example, a formerly forested area might be replanted with trees. The use of seeds should be expanded to include soil, mulch
and plant materials.
The Departments agree. As stated in the best practices report, the goal of
reclamation should be to return the developed area to native vegetation (or predisturbance vegetation in the case of agricultural land returning to production) and
restore the original hydrologic conditions to the maximum extent possible.
Miscellaneous comments on standards.
1. Gathering lines are already adequately regulated. The rural gathering lines from
the Accident Dome underground storage wells are under very high pressure when
gas is being injected into the wells during warm months and extracted during the
winter months. The standards for material and construction adequately address
this activity.
The federal Pipeline and Hazardous Materials Safety Administration (PHMSA), has
relatively few requirements for gathering lines. It is in the process of collecting new
information about gathering pipelines in an effort to better understand the risks they
may now pose to people and the environment. If the data indicate a need, PHMSA
may establish new safety requirements for large-diameter, high-pressure gas
gathering lines in rural locations. Pending this action, the Departments are
recommending two simple and commonsense requirements: that the locations of the
lines be registered through Miss Utility, and that all pipelines and fittings be
designed for at least the greatest anticipated operating pressure or the maximum
regulated relief pressure in accordance with the current recognized design practices
of the industry.
2. This is not a difference of opinion, this is basic physics. Gas when released goes
straight up. Therefore, gas in a distant fissure far from the bore is not going to
make its way into the pipe. It will be released into the air.
The horizontal borehole runs through the target formation thousands of feet below
the surface. The pressure is very high at this depth. In normal circumstances, the
methane, fracking fluid and water in the formation, like other gases and fluids, tend
to flow from an area of higher pressure to lower pressure; that is, to flow from the
formation into the wellbore.
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FORCED POOLING
1. I have serious concerns about your suggestion of "forced pooling" of properties.
Forced pooling is a violation of property rights.
2. Citizens of Maryland should be assured that the State will never force landowners
who own their mineral rights to allow extraction of the resources (gas) under their
land without their consent.
Forced pooling compels landowners who have not leased their gas rights to allow a
driller to extract gas from their land. It is common in oil and gas states, although the
specific provisions vary from state to state.
In New York, for example, an applicant for a permit to drill an oil or gas well must
include, in the permit application, a map showing the contiguous area from which the
well will be able to extract oil or gas. This area is called a spacing unit, and it may
include land for which the applicant does not hold mineral rights. If the applicant
controls mineral rights to at least 60 percent of the acreage in the proposed spacing
unit, the applicant can petition for compulsory integration, as forced pooling is called
in New York. There is a hearing process before the state acts on the petition. The
landowner has three integration options: as a royalty owner; as a non-participating
owner; or as a participating owner. These options have different formulas for
sharing risks, costs and revenues in the pooled area
Maryland does not have a law that expressly forces or compels mineral interest
owners to pool their resources with those of other mineral interest owners. Maryland
does, however, expressly recognize and regulate voluntary pooled units. The
Departments are not recommending any statutory change that would allow forced,
compulsory, or involuntary pooling. If such a change were to be made, it would
require an act of the Maryland legislature.
IMPACTS ON CHESAPEAKE BAY
1. Fracking will make it more difficult to meet the Chesapeake Bay Total Maximum
Daily Load (TMDL).
a. Fracking and its associated infrastructure, including well pads, pipelines
and compressor stations, will result in additional deforestation, increased
impervious surfaces, construction run-off, and other land-use degradation
that will likely impact the Bay TMDL. Fracking fluid spills or waste
would also contaminate the Bay watershed.
b. The Department’s treatment of stormwater runoff from increased oil and
gas development bears particular importance in light of Maryland’s efforts
to comply with EPA’s mandates under the Chesapeake Bay Total
Maximum Daily Load (TMDL). First, some of the lands proposed for
hydraulic fracturing drain in to the Potomac River that feeds the
Chesapeake Bay. Increased industrial development within the Chesapeake
Bay watershed will likely have substantial effects on stormwater pollution
levels.
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While most of the Maryland portion of the exploitable Marcellus Shale lies outside
the Chesapeake Bay watershed, the Allegany County portion and part of the Garrett
County portion are in the watershed, albeit at a distance, and therefore could
theoretically have an adverse impact on the Bay. The Bay TMDL has been
established for nutrients and sediment. Deforestation, increased impervious surfaces
and construction run-off have the potential to increase the amount of nutrients and
sediment that reaches surface water.
Statewide regulations already in place governing stormwater controls, and other
Statewide regulations that are planned, will minimize this increase. In addition, best
practices have been proposed specifically for Marcellus Shale gas development to
further reduce the risk of an impact to surface waters. For example, the Departments
recommend as a mitigation measure that a no-net-loss of forest standard be
implemented, varying for temporary or permanent loss. In order to prevent,
minimize, or mitigate increased impervious surfaces, run off, or other water and land
degradation, the Departments recommend that erosion and sediment, and stormwater
management staff receive additional training, and mandate the use of closed loop
handling of drilling mud and cuttings, “zero-discharge” pads, and various other
practices, including the strict adherence to current requirements of erosion and
sediment, and stormwater management regulations. In addition, drilling, well casing,
HVHF, water appropriations and waste management practices will be tightly
monitored and controlled in order to prevent contamination to local waters and the
Bay.
In 2013, the Chesapeake Bay Program Scientific and Technical Advisory Committee
(STAC) addressed this issue through a workshop on “Exploring the environmental
effects of Shale gas development in the Chesapeake Bay Watershed.” One of the key
recommendations from the STAC workshop was the development of a rigorous
monitoring and analysis program in order to determine if impacts to the Bay were
occurring. In addition, the STAC also recommended many of the same practices that
Maryland is considering such as landscape scale planning at the project level vs.
individual well level and a rigorous set of environmental setbacks to protect sensitive
aquatic habitats and waterways. More information on the STAC workshop can be
found here: http://www.chesapeake.org/pubs/300_Gottschalk2013.pdf.
In 2014, Maryland implemented a baseline surface and groundwater monitoring
program to characterize pre-drilling conditions in the jurisdictions most likely to be
affected by Marcellus gas well development. In addition and as a component of any
individual permit, an applicant is required to conduct two-years of baseline surface
and groundwater monitoring before any drilling can occur. This will ensure that any
deviations from baseline conditions resulting from drilling are identified so as to be
appropriately addressed.
2. As a result of recent legislation, most Marylanders will soon pay more in
stormwater utility fees designed to fund the TMDL compliance efforts. Requiring
Marylanders to pay more for stormwater protection while largely absolving the oil
and gas industry from these efforts everywhere except the well pad is unjust.
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The federal Clean Water Act requires Maryland and other States to meet water
quality standards to protect public health and restore streams, rivers, groundwater
and drinking water. The actions needed to achieve this include reducing the amount
of pollution that ends up in our waters as a result of heavy rains washing
contaminants off the land into our waterways. Under the authority of the federal
Clean Water Act, the U.S. Environmental Protection Agency has required all
Chesapeake Bay Watershed states to develop Watershed Implementation Plans
(WIPs) to achieve the Chesapeake Bay Total Maximum Daily Load (TMDL)
requirements for nitrogen, phosphorus and sediment. Meeting the TMDL will require
us to address the existing sources of pollution as well as prevent or offset the new
sources of pollution. The purpose of the stormwater remediation fee passed by the
Maryland General Assembly in 2012 and mandatory in Baltimore City and the nine
most populous counties of Maryland is to fund programs and projects to meet the
stormwater pollutant load reductions mandated under Federal and State law. The
money will be spent in the jurisdiction in which it is collected.
Various Statewide regulations are already in place to minimize the pollution that
results from new development, including construction for roads and pipelines. Some
of the recommended best practices will reduce the pollution further. In addition, the
State is developing a program to offset the remaining nutrient and sediment pollution
from new development.
Everyone in the watershed contributes to the stormwater problem and everyone must
be part of the solution. The oil and gas industry is not excused.
INDIVIDUAL WELL PERMIT
1. It is noted that on page 20 operators are required to consider API standards and
guidance documents in the preparation of well plans. This is consistent with some
other states inclusions of API standards in their regulatory process and may work
to improve the well planning process by incorporating the engineering rigor found
in these documents. However, caution should be exercised in the application of
these requirements. This is due to the fact that as performance based standards, a
variety of engineering solutions can be found in these documents. The
requirement that the plans must “follow a normative element of a relevant API
standard” or otherwise “explain why and demonstrate that the plan is at least as
protective as the normative element” could lead to conflicting requirements as
performance-based standards often contain multiple normative elements which
allow for the use of engineering judgment in their application.
The Departments agree that caution must be exercised in the use of API standards;
however, the Departments do not think there is a significant risk of conflicting
requirements. In API standards, “normative” elements are those provisions that are
required to implement the standard. “Normative” corresponds to “shall,” which
denotes a minimum requirement, while “should” denotes a recommendation or
something that is advised but not required in order to conform to the standard. If a
standard applies to an operation, there should be no reason not to conduct that
operation in a way that provides at least the measure of protection provided by a
mandatory minimum requirement.
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2. The applicant should be required to notify the owners of any drinking water well
within one kilometer (3,300 ft) of active development area outlined in the permit.
Current regulations require that the applicant for a permit certify that the applicant
has notified, in writing, each landowner and leaseholder of real property that borders
the proposed drillable lease area of the applicant’s intention to file an application for
a permit to drill a well. COMAR 26.19.01.06C(9). More recently in 2012, Section
14-110.1(c) of the Environment Article was amended to provide for a presumptive
impact area of 2500 feet from the vertical well borehole. The Departments agree that
all those within the presumptive impact area should be notified of the application and
MDE will seek such a change in the regulation.
3. COMAR 26.19.01.10 V requires the permittee to provide the state with a copy of
all electric, radiation, sonic, caliper, directional, and any other type of logs run in
the well. The statement is too weak because it does not require the permittee to
run all these logs.
Each well will be considered individually. The best practices report states that an
application for a well permit must include a plan for integrity and pressure testing.
There may be various combinations of logging done on individual wells. The
Department of the Environment will specify in the individual permit the type of
logging to be done. This could be codified in regulation but the greater flexibility of
reserving the specifics for the permit decisions may be more advantageous.
4. The list of items from 1 to 26 is incomplete and is basically a list of terms. The
list should specify what is required such as: locations of; project plans and
specifications, plans, procedures and schedules. Requirements should be clear
about the level of detail expected for each item.
The Departments agree and will clarify the required level of detail in the regulations
and in the permit application form. The Department of the Environment has the right
to ask for documents and information if necessary to complete the application and, if
any of the elements are lacking in appropriate detail, it will exercise that right.
LEGISLATION
1. The State and the Advisory Commission should advocate for legislative
protections like a Surface Owners Protection Act (SOPA). The Act needs to be
comprehensive and address reasonable and fair consideration for the surface
owner, with monetary compensation commensurate with the highest possible loss
the surface owner could suffer as a result of drilling practices and drilling
malpractices. The consideration for problems that are caused by drilling that will
be discovered only as a matter of time need to be included.
The Departments and the Advisory Commission recommended in December 2011 that
the legislature adopt a comprehensive SOPA. A committee of the Advisory
Commission was formed to discuss, among other things, the provisions of a SOPA.
The Commission unanimously agreed that a SOPA should protect surface owners
who are not mineral rights owners; the SOPA should include a procedure for the
negotiation of the siting wells, roads and other infrastructure; and that the SOPA
should mandate reasonable compensation for damages. A motion passed, not
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unanimously, that the SOPA should also apply to surface owners who lease their
mineral rights in the future. There was no consensus on how to manage dispute
resolution or whether the SOPA should protect those who leased their mineral rights
in the past, to the extent permitted by the Constitution. The areas of agreement did
not amount to a comprehensive SOPA, and the Departments decided not to proceed
with an incomplete bill.
2. The Best Practices Policy, and any legal rights therein, should apply to contracts
that were signed in the past.
Article I, Section 10 of the United States Constitution forbids any state from passing a
law that retroactively impairs the obligation of contracts. The Advisory Commission
was not able to reach consensus on whether the SOPA should protect those who
leased their mineral rights in the past, to the extent permitted by the Constitution.
3. Landowners should be allowed to cancel any lease they entered into, even if it is
after the company has begun drilling.
Such a blanket provision would likely violate Article I, Section 10 of the United States
Constitution. See above.
4. Maryland should adopt an adequate State severance tax; the funds could be
administered by a publicly appointed commission similar to the Marcellus Shale
Advisory Commission or by an ombudsman panel.
SB 535 was introduced during the 2014 legislative session to levy a State-level
severance tax. The taxes would go into a fund to be used by the State to monitor,
mitigate and remediate adverse impacts caused by natural gas exploration or
production that cannot be attributed to a specific permittee or where the permittee is
financially insolvent or no longer exists. This legislation did not pass. The
Departments do not see the need for a commission or an ombudsman panel to
administer the fund.
5. We strongly urge the funding (via a severance tax) of a special conservation fund
of $100 million for restoration activities resulting from drilling legacy issues. The
funds collected to address legacy issues are in addition and separate from funds
that will be collected to address short-term environmental damages resulting from
drilling.
The combination of financial assurances and pollution insurance should prevent the
kinds of legacy issues that occurred in coal mining because regulations were not in
place to require reclamation of the mines. The severance tax bill (SB535) that was
introduced this year would have established a fund to be used by the State to monitor,
mitigate and remediate adverse impacts caused by natural gas exploration or
production that cannot be attributed to a specific permittee or where the permittee is
financially insolvent or no longer exists. Under this legislation, if the amount in the
fund were to exceed $10 million, it could be used to benefit the area where drilling
occurred. This could include conservation projects. This legislation did not pass.
6. The rights of resident communities should supersede any rights afforded to
corporate interests and absentee owners.
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The Departments have tried to strike a balance between the property rights and the
interests of resident communities, both of which should be protected. The proposed
best practices are designed to protect residents.
7. The agencies/MSAC should advocate in the 2014 Legislative session for a bill
moving the PSC to regulate and permit rural gas gathering lines within the state.
The regulations in COMAR Title 20, Subtitles 56, 57 and 58 are inadequate. The
bill could also address permitting, siting, construction and operation of all
pipelines outside the CGDP process.
The PSC has the authority to assure that intrastate gathering lines comply with the
pipeline safety regulations. The federal Pipeline and Hazardous Materials Safety
Administration (PHMSA) is in the process of collecting new information about
gathering pipelines in an effort to better understand the risks they may now pose to
people and the environment. If the data indicate a need, PHMSA may establish new
safety requirements for large-diameter, high-pressure gas gathering lines in rural
locations. Pending this action, the Departments are recommending two simple and
commonsense requirements: that the locations of the lines be registered through
Miss Utility, and that all pipelines and fittings be designed for at least the greatest
anticipated operating pressure or the maximum regulated relief pressure in
accordance with the current recognized design practices of the industry.
8. UMCES-AL recommends that applicants wishing to drill wells be required to
notify property owners residing within the established setback that an application
has been filed for development. This notification requirement should also apply to
citing of compressor stations and other ancillary equipment. Applicants who wish
to construct ancillary infrastructure are required to notify all landowners whose
property line falls within the current required setback (1,000 feet.)
Current regulations require that the applicant for a permit certify that the applicant
has notified, in writing, each landowner and leaseholder of real property that borders
the proposed drillable lease area of the applicant's intention to file an application for
permit to drill a well. COMAR 26.19.01.06C(9). More recently in 2012, Section 14110.1(c) of the Environment Article was amended to provide for a presumptive
impact area of 2500 ft from the vertical well borehole. The Departments agree that
all those within the presumptive impact area should be notified of the application and
MDE will seek such a change in the regulations.
Ancillary infrastructure will be considered in the Comprehensive Gas Development
Plan (CGDP). The Departments will require that a similar notice be made so that
interested persons can participate in the public process of reviewing the CGDP.
9. Any and all fracking companies that may be allowed to do business in Maryland
should have to contribute substantially to a fund that helps significantly increase
our renewable energy portfolio. That way at the very least the damage that
fracking will inevitably do every step of the way will pave a path toward a green,
healthy environment, economy and future.
It is not clear why natural gas companies should be required to contribute to such a
fund when coal mining companies, for example, do not. Nevertheless, the Regional
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Greenhouse Gas Initiative may provide a model for such a program, if offsets of
greenhouse gas emissions were required. The money raised from the sale of offset
credits directly funds energy efficiency and cleaner energy programs that will lower
greenhouse gas emissions.
10. All legal hearings related to fracking/drilling will be held in the court system of
that county. However, if it involves federal issues, it may be heard in the federal
court system.
The question of the jurisdiction of federal and state courts is outside the control of the
Departments. MDE regulations provide, for its own hearings, that “If the hearing
relates to the issuance of a permit for or with respect to a specific well, it shall be
held in the county or municipal corporation where the well is located.”
NOISE
1. Zoning and Noise. We strongly recommend that the BMP's recommend local
zoning be adopted in Garrett County so that it can better protect its citizens in this
regard. If the Commission will not recommend that local zoning is integral to best
management practices, then would they, at a minimum, provide recommendations
for specific zoning elements; e.g., noise.
Zoning is an excellent way to separate incompatible land uses; however, authority to
enact zoning rests with the local jurisdictions. Allegany County has adopted
comprehensive county-wide zoning; however, Garrett County has not. It is a local
matter over which the Departments have no control. Even without zoning, however,
Garrett County has adopted the state noise regulations, see § 157.063 of the Garrett
County Code.
2. Noise and setbacks.
a. “Noise” is viewed as a potentially significant industrialization issue. We
are having difficulty rationalizing the largely noise-driven setbacks
appearing in this section with the noise discussion in Section VI.N. For
instance, the setback table specifies 1,000 ft. between an occupied
building and a compressor station, while Section VI.M seems to call for at
least 3,000 ft. unless the only engine/motor source is electric. Something
to be changed or explained? Are we misreading?
b. Wouldn’t it be useful to calculate the implied setback distance from, say,
active drilling rigs or compressor stations whose noise level at the source
is surely known or readily measured?? Has this been done?? Is this the
basis for Section IV setbacks though not explicit??
c. Beyond specifying setbacks broadly based on state-level standards as
above, one could (1) identify specific residential or commercial facilities
around a particular proposed well/well pad, (2) specify maximum noise
levels at these specific locations as part of the application for each well
(per local standards), and (3) mandate that the plan for each well/well pad
include an analysis of how the standards will be met for the specific “noise
sources” that are part of the industry application. (Will the well plans
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include locations and design parameters of compressor stations as well as
drilling rigs??)
The UMCES-AL report recommended requiring quieter equipment, restricting hours
of operation, and using mitigation techniques like barriers and mufflers where
natural noise attenuation would be inadequate. That report did not, however,
indicate how to evaluate whether natural noise attenuation would be adequate, nor
did it discuss the Maryland noise standards.
Setbacks alone cannot be a surrogate for noise regulations because topography and
other site-specific issues greatly affect how noise travels. The Departments have
chosen instead to require compliance with the statewide daytime and nighttime noise
levels that are specific to the type of property that receives the noise and is being
protected: residential, commercial or industrial. The Departments will require that
the applicant for a permit submit a plan for complying with the noise standards for
all its permitted operations and for verifying compliance after operations begin.
3. Noise levels and controls.
a. Maryland noise statutes appear to be limited regarding low frequency
noise. However, there is data to indicate that low frequency noise may be
associated with natural gas infrastructure and specifically compressor
stations. Noise can cause permanent medical conditions such as
hypertension and heart disease, hearing impairment, communication
problems, sleep disturbance, cognitive effects such as memory problems,
reduced performance, behavioral symptoms, and more. Low-frequency
noise [LFN] can also cause Vibroacoustic disease, leading to
cardiovascular symptoms and decreased cognitive skills. We believe it is
incumbent upon Maryland to ensure that adequate protections are in place
to protect against LFN. Typical noise mitigation measures for gas supply
and storage infrastructure include acoustic cladding for buildings, the use
of sound attenuators on ventilation systems, acoustic lagging on pipework,
multi-stage control valves, gas turbine exhaust silencers, acoustic
enclosures on pumps, low speed cooler fans and the use of electric rather
than gas powered compressors.
b. Require that all compressors and other above ambient levels noisecreating equipment be fully enclosed and muffled to normal ambient
levels.
c. Add: Sound levels should not exceed 115 dBa at any time.
d. You should address noise from drilling rigs and compressor stations and
idling trucks, especially at NIGHT!
e. Instead of using “residential” consider using “noise-sensitive locations.”
This would allow expansion to incorporate a number of other nonresidential noise sensitive areas including areas identified for
environmental considerations in this report. Noise sensitive uses may
include uses such as hospitals and parks.
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Most noise standards, including Maryland’s, are based on A-weighted measurements
that deemphasize or ignore low frequency noise. The effects of infrasound and low
frequency noise are being studied and the Departments will consider changes to the
noise regulations in the future if evidence justifies it. A few studies have suggested
that excessive exposure to low frequency noise can cause a condition which has been
termed vibroacoustic disease (VAD). However, the strength of these studies and the
significance of their conclusions are uncertain, and it does not appear that VAD has
been established as a known medical condition outside of these studies.
With respect to compressor stations, the statewide noise regulations will apply to any
stations over which Maryland has control. Interstate compressors are authorized by
the Federal Energy Regulatory Commission (FERC) under a Certificate of Public
Convenience and Necessity (CPCN). For efficiency of administration, FERC has
established a blanket certificate program as well as a site-specific process for issuing
CPCNs. Both require adherence to maximum noise limits at noise sensitive areas in
existence at the time of the CPCN. Noise sensitive areas include schools, hospitals,
and residences. A noise survey must be conducted after the compressor station is in
operation and, if the noise levels are exceeded, corrective measures must be taken.
No foundation was offered for reducing noise to “normal ambient levels” or to add a
never-to-be-exceeded sound level. These approaches are not consistent with noise
regulation in Maryland which focuses on levels that must be maintained at the
property line of affected entities.
The noise standards are lower for nighttime hours than for daytime hours.
Recognition of “noise sensitive locations” is a good suggestion, and the Departments
will incorporate that concept into the review of the Comprehensive Gas Development
Plan and the individual well permit. Site-specific noise provisions can be
incorporated into individual permits.
4. Monitoring and reporting.
a. Making the industry responsible to monitor and report excess noise levels
may not produce accurate reporting. The permittee should be required to
have continuous monitoring for sound during high development activity;
such as stimulation of the well. Funding for this monitoring will be paid
by the permittee, with all reports to be received by MDE for compliance of
the permit. We recommend that the Departments require the County to
select and hire an independent contractor—at the expense of the
permittee— to conduct periodic noise monitoring and additional noise
monitoring in response to a complaint.
As noted above, the Departments will require that the applicant for a permit submit a
plan for complying with the noise standards for all its permitted operations and for
verifying compliance after operations begin. In the draft Best Practices report, the
Departments indicated that they may require the permittee to hire an independent
contractor to conduct periodic noise monitoring and additional noise monitoring in
the event there is a complaint. The reports would be submitted to MDE and any
necessary compliance investigations will be carried out by the local jurisdiction. In
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determining the amount of the application and permit fees the Department is
authorized to set under Section 14-105 of the Environment Article, MDE will
consider whether funds will be needed to purchase noise monitoring equipment.
PRE-DEVELOPMENT BASELINE DATA
1. We believe that there is a strong need for pre-development testing of water wells
and aquifer samples within a kilometer of leased mineral rights for a number of
elements, along with isotopic fingerprinted methane.
As stated in the draft report, the Departments will develop standard protocols for
baseline and environmental assessment monitoring. This will include sampling
existing private drinking water wells within 2500 feet of the proposed gas well,
provided the owner of the drinking water well consents to the sampling. If there are
no drinking water wells within that distance, the Department of the Environment will
require the installation of one or more monitoring wells. Isotopic analysis for
methane can only be performed if there are high enough concentrations of methane.
It will be required if circumstances warrant.
2. The State needs to develop specific requirements for surface water testing
parameters, whether there will be baseline monitoring of air quality, and what
living species and habitat will be monitored.
The Departments, in collaboration with University and government researchers, have
developed a comprehensive monitoring plan for surface waters associated with
Marcellus Shale natural gas development in western Maryland (if and when it is
permitted). The draft monitoring plan is currently under review and will be included
in the final draft report when it is posted for comment. The sampling approach
recommended for evaluating the impacts of Marcellus Shale gas extraction on
surface waters uses a BACI (before-after-control-impact) model. The sampling
design will measure conditions in stream/river reaches associated with the
development of a particular gas well pad (or associated infrastructure) BEFORE
(baseline monitoring) the planned activity, and then compare the findings to those
conditions measured in the same stream/river reaches during and AFTER the activity
occurs. The recommended monitoring plan also includes measurements of
stream/river conditions in CONTROL stream/river reaches that will not be affected
by gas extraction-related activities, and then will compare these data with
measurements of stream/river conditions in affected or IMPACTED stream/river
reaches. Data collected from stream reaches include continuous conductivity and
temperature, a full suite of water chemistry parameters (including all or a
combination of inorganic constituents, gross alpha and beta, polycyclic aromatic
hydrocarbons, surfactants ,and stream methane) and characterization of the
biological communities (e.g., fish, benthic macroinvertebrate, and presence/absence
of golden algae).
3. Two years of background data is not necessary. At least, consideration should be
given to whether there is already sufficient data available. The need for
monitoring and the area to be monitored should be related to the tract size.
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In 2012, The Maryland Department of Natural Resources evaluated its existing
monitoring networks in Garrett County and determined that data exists for about 10
percent of all stream or river reaches present. In addition, DNR determined that
although the existing data is good information (i.e., quality data), it is limited (i.e.,
lacks parameters identified as important to assess impacts from Marcellus Shale gas
development) and addresses a different set of management questions.
The first draft comprehensive monitoring plan developed by the Departments
recommended at least three consecutive years of stream/river monitoring to establish
baseline conditions. Three consecutive years of monitoring could provide a
reasonable opportunity to collect data during a wet, dry, and near-normal
precipitation year. Two years of baseline monitoring are less likely to capture a wet
and a dry year and will probably fail to document the full or nearly-full range of
annual fluctuations in stream/river conditions. If only one year of pre-drilling
stream/river monitoring is conducted, useful information on seasonal fluctuations can
be collected for that year and that year only. One year of baseline data cannot
document annual fluctuations in conditions at a given stream or river location.
4. Pre-operational sampling to establish background air quality should also be
required for ancillary facilities, such as compressor stations, that have the
potential to emit gases.
There are other ways to monitor air quality in the vicinity of compressor stations and
methods for detecting leaks. Pre-operational sampling is not necessary.
PROCESS
1. We are concerned about the Marcellus Shale Safe Drilling Initiative Advisory
Commission as it relates specifically to transparency in decision-making process.
How are reports developed: is it by vote, by building consensus, are votes public,
can there be dissenting reports, and specifically, are all the stakeholders' positions
made public? These are concerns we have so that we understand better how
decisions and reports are accomplished. We wish to know whether all
stakeholders’ views are represented and where divided opinion exists.
The Marcellus Shale Safe Drilling Initiative Advisory Commission provides full
transparency through open meetings and through a dedicated website providing
access to all documents, meeting minutes, presentations and other materials used for
discussion. One example of transparency is a report of the Commissioners’
responses to a survey that was designed to elicit their opinions on proposed best
practices. The purpose of the survey was to identify which topics required further
discussion at upcoming Commission meetings. The individual responses are posted
on-line.
The composition of the Commission is designed to provide representation across all
stakeholder groups. In addition, stakeholders have the option to provide their
viewpoints to the Commissioner best suited to represent their views and to participate
in the public comment period at the end of each Commission meeting. The Marcellus
Shale Safe Drilling Initiative reports are produced by the Departments and are
informed by the discussions that take place at the Commission meetings. The final
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version of the best practices report will document the recommendations of the
Departments and document the degree of consensus among the Commissioners.
The Departments seek to identify points of consensus among Commission members
and also realize that there may be dissenting opinions.
2. We are concerned that, in some cases, the UMCES-AL Best Management
Practices Report and Recommendations are weakened rather than followed or
strengthened. Will Commissioners be able to vote on these changes made by
MDE?
In most instances, the Departments accepted the UMCES-AL best practices
recommendations, and, in certain situations, strengthened them. Justifications for
recommendations that the Departments rejected or modified are clearly identified in
the report. Additional changes are being made in the report as a response to
comments. The Departments will consult with the Commission on the final set of best
practices recommendations.
3. The BMPs are vague: the proposed BMP's have language such as "where
practicable," "encouraged," and "reasonable use." "Where practicable" is used six
times in the proposal, "encouraged" is used three times, and "reasonable use" is
used eight times. That is a total of 17 occurrences where common understanding
is likely not to occur. Also, monitoring and enforcement are far more difficult
when regulations and/or BMP's use such language. How can penalties be
instituted, if at all, with such vagueness?
“Practicable” is a term often used in laws and regulations. It is used
interchangeably with “feasible” and describes an idea or activity that can be brought
to fruition or reality without unreasonable demands. In the draft Best Practices
report, “practicable” is often used in connection with a plan that, once approved,
becomes part of the permit. For example, the draft report says “Flowback and
produced water shall be recycled to the maximum extent practicable. Unless the
applicant can demonstrate that it is not practicable, the permit shall require that not
less than 90 percent of the flowback and produced water be recycled, and that the
recycling be performed on the pad site of generation.” The applicant for a drilling
permit must submit a plan for storage, treatment and disposal of water and
wastewater. The Department of the Environment will review that plan, and any claim
by the applicant that recycling is not practicable. The approved plan, which will be
incorporated into the permit, will be specific as to the recycling and sufficiently clear
to determine compliance or noncompliance.
“Encouraged” is often used in the draft report in circumstances where the
Departments have no legal authority to require a certain action, or to indicate the
Departments’ preference where there are multiple permissible options.
“Reasonable use” is the name of a doctrine or policy on water rights. Maryland
regulations state: “Maryland follows the reasonable use doctrine to determine a
person's right to appropriate or use surface or ground water. A ground water
appropriation or use permit or a surface water appropriation or use permit issued by
the Department authorizes the permittee to make reasonable use of the waters of the
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State without unreasonable interference with other persons also attempting to make
reasonable use of water. The permittee may not unreasonably harm the water
resources of the State.” COMAR 26.17.06.02.
4. The report should not be limited to the Marcellus Shale because the Utica and
other formations may also be tapped in the future.
The findings and conclusions regarding gas exploration in the Marcellus Shale may
also apply to other formations. That question will have to be considered if and when
other productive formations are identified.
5. We reiterate our recommendation that this “Study Part II” include a new section
that outlines and states the goals and policy direction for Marcellus gas
development in Maryland. By clearly stating the direction Maryland is taking, all
stakeholders (the industry, landowners, local government, interested and
concerned parties, and statewide parties) can see and understand the purposes and
intended uses of the best practices.
Goals and policy directions are provided in the publicly available Executive Order
01.01.2011.11. The State is still in the process of collecting the facts and evaluating
the science and has not settled on a “direction.” As stated in the Executive Order,
the State is determining the best way Marcellus gas development could be done in
Maryland without risk to public safety, public health and the environment, and to
advise the Administration on the remaining risks. Also note that the report
development process includes opportunities for the involvement of all types of
stakeholders, including representation on the Advisory Commission and the chance to
provide comment on report content.
6. The report is based on the recommendations of the contractor, UMES-AL, and
therefore does not take a “systems” view of the full breadth of Marcellus gas
development. First, this report should identify additional best management
practices that are recommended for other state and local government departments
and agencies so their activities can be coordinated and responsive to the overall
thrust of the Safe Drilling Initiative. Second, the report appears to have selectively
identified BMP’s for the industry, but does not clearly identify the BMP’s that
should be adopted by state agencies. It is important that BMP’s be recommended
and adopted by state departments as well as the drilling industry as the Marcellus
is developed.
The report addresses methods and techniques for the actual operations of gas
exploration and production, planning, opportunities for other state and local
agencies to participate, and processes for government review. The CDGP and other
best practices will address all aspects of the Marcellus shale gas drilling activity.
Certain elements of the best practices report will be implemented by MDE and DNR
or through partnerships with county and local authorities. If the decision is to allow
Marcellus shale gas development, the Departments anticipate that the
recommendations will be embodied in regulations and guidance.
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7. The CGDP as presented by the Departments is a conceptual outline and has not
come under broad scrutiny by the public, the industry, and elected government
representatives.
The CGDP has been presented as a concept, but with a significant amount of detail
regarding principles, content, and process. The Departments are confident that it is
clear enough for interested persons to understand and comment on.
Before any individual permit for a production well is issued, the applicant must have
an approved CGDP. The development and approval of the CGDP requires
evaluation by local and state agencies, followed by a public review, involving a
stakeholder group, and approval process. The stakeholder group will include the
company, local government, resource managers, non-governmental organizations,
surface owners, and other affected individuals or organizations. This transparent and
public process will provide ample opportunity for scrutiny of actual CGDPs.
8. The study should explicitly acknowledge the political reality that the proposed
“best practices” amount to an initial negotiating position held by Maryland, in the
face of oil and gas industry pressure.
All stakeholders, including oil and gas industry representatives, have had the
opportunity to provide comment on the content of the best practices report. It is up to
the State to determine which best practices will ultimately be required.
9. Standards and practices are changing constantly. What was a good practice or
standard last year when the study was conducted may have been superseded with
better practices or proven to not provide protections it was designed to provide.
We could not find a process by which there is on-going updating and evaluation
of BMPs as the study process moves forward.
The Departments acknowledge that standards and practices change. The best
practices in the report do not preclude the use or introduction of new and innovative
technologies. If this type of gas activity is allowed, the development of the industry
will be closely tracked by State agencies through comprehensive monitoring of
environmental conditions, best practice performance monitoring and rigorous
inspection and enforcement procedures. This information will be used as a
benchmark for identifying and implementing additional practices that may better
protect the environment, public health and safety and the community. If needed,
regulations will be updated.
10. I much prefer a regulation that requires the introduction of new best practices by
the industry as new technologies emerge that can provide more protection to
public health and safety and to the environment. Better technology requirements
could be a requirement every five (?) years if improvements exceed some pre-set
thresholds, e.g. a reduction of some air pollutant by 20 percent.
As stated in the previous response, the State will closely monitor the performance of
the industry and identify opportunities to adopt best practices that are more
protective of public health, safety and the environment. The industry is rapidly
developing new technologies and practices for extraction of shale gas. The
Departments prefer to retain flexibility rather than setting thresholds or time limits,
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to ensure the rapid adoption of new technologies should monitoring confirm
improved performance. With respect to air pollution controls, the Departments are
proposing to require best available control technology.
11. We are very supportive of the best practices report as drafted. As an organization
that works on the issue of unconventional gas development across the country,
these BMPs, if adopted into regulation in Maryland, would be some of the best, if
not the best, in the country. However, we are concerned that the timeframe for the
development of regulations from these recommended Best Practices is indefinite.
We understand that there are public concerns about the development of new oil
and gas regulations before the full report from the Commission is available.
However, current Maryland regulations on oil and gas are outdated. Regardless of
whether someone supports or opposes shale gas development, it serves the State
to have the best regulations in place to protect the health, safety, and natural
resources of Maryland.
The Departments agree that current regulations are outdated and that it is imperative
to update the regulations in the event that shale gas development is permitted in the
State. In an open letter to the public from Secretary Robert Summers, dated April 26,
2013, MDE commits to proceeding methodically and cautiously to develop stringent
regulations that will protect Marylanders in the event hydraulic fracturing is allowed.
As a preliminary step, the Departments must first finalize the best practices report
and review the additional results produced from the ongoing economic, public health
and risk studies, before proposing any specific regulatory revisions.
CLASSIFICATION OF WASTES UNDER THE RESOURCE CONSERVATION AND
RECOVERY ACT (RCRA).
1. If drilling were to proceed in Maryland, COMAR regulations should treat wastes
from oil and gas facilities as RCRA hazardous materials. As the Departments are
aware, the EPA in 1988 determined oil and gas wastes as nonhazardous despite
acknowledging that known toxics like benzene appear at high levels. While many
of the same chemicals found in oil and gas production the EPA already regulates
as hazardous, once these same materials emerge from gas wells as flowback or
produced water, the law exempts them from this treatment.35 The reason
Maryland should treat oil and gas waste as RCRA hazardous is that EPA’s 1988
determination is out of date.
For the reasons explained below, MDE believes that wastes from oil and gas
production can be managed safely under the existing practices, as augmented by the
35
We would like to correct one error in the commenter’s statement, namely that “While many of the same
chemicals found in oil and gas production the EPA already regulates as hazardous, once these same
materials emerge from gas wells as flowback or produced water, the law exempts them from this
treatment.” The statement implies that the chemicals used in oil and gas production are regulated under
RCRA as hazardous before they “emerge from the gas wells.” EPA does not regulate materials as
hazardous under RCRA until they become wastes. When chemicals are in commerce or in use, they are not
wastes and therefore cannot be hazardous wastes.
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new best practices, without classifying them as hazardous wastes. Therefore the
Department does not propose to eliminate the exemption at this time.
In 1988, EPA announced its determination that regulation of wastes from the
exploration and production of oil and gas did not warrant regulation under Subtitle C
of the Resource Conservation and Recovery Act (RCRA) that applies to “hazardous
wastes.” The exemption is codified at 40 CFR 261.4(b)(5), which provides: "The
following solid wastes are not hazardous wastes: ... Drilling fluids, produced waters,
and other wastes associated with the exploration, development, or production of
crude oil, natural gas or geothermal energy." Maryland adopted an identical
regulation.
As directed by Congress, EPA in 1988 considered three major factors: 1) the
characteristics, management practices, and impacts of these wastes on human health
and the environment; 2) the adequacy of existing State and Federal regulatory
programs; and 3) the economic impacts of additional regulations on the exploration
and production of oil and gas.
Data on the characteristics of the wastes were sparse in the 1980’s, and HVHF
wastes were not tested (and probably not being generated by the industry in 1988).
EPA reported, however, that
For crude oil and natural gas wastes, EPA sampled liquids and
sludges from several locations. Drilling fluids were sampled at drilling
operations while produced water and tank bottoms were sampled at
production operations. Samples from central treatment and disposal
facilities and central pits contained mixtures of all wastes including
associated wastes. The Agency found that organic pollutants at levels
of potential concern (levels that exceed 100 times EPA's health-based
standards) included the hydrocarbons benzene and phenanthrene.
Inorganic constituents at levels of potential concern included lead,
arsenic, barium, antimony, fluoride, and uranium.
53 Fed.Reg. 25446, 25448 (6 July 1988).
EPA concluded that some of the wastes would be classified as hazardous if the
exemption were lifted. “EPA estimates that approximately 10 to 70 percent of largevolume wastes and 40 to 60 percent of associated wastes could potentially exhibit
RCRA hazardous waste characteristics under EPA's regulatory tests.” 53 Fed.Reg.
25455.
EPA also evaluated the waste management techniques in use in the 1980’s.
Current practices include the use of reserve pits for drilling
wastes; landspreading of reserve pit contents; disposal of produced
waters through Class II underground injection wells; disposal of
produced water in unlined pits; discharge of produced water to
surface waters; roadspreading; use of commercial facilities for
treatment and disposal of drilling wastes and produced water; and
some practices unique to the Alaska North Slope.... Less frequently
used current practices discussed in the report are closed-cycle drilling
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mud systems, annular disposal of produced water and drilling fluid,
and trenching of reserve pits to dispose of reserve pit fluids.
53 Fed. Reg. 25448-49.
EPA considered the damage that has been caused by oil and gas operations. It
concluded that wastes from crude oil and natural gas operations have endangered
human health and caused environmental damage when managed in violation of State
and Federal requirements. Moreover, in some instances damage occurred even where
wastes were managed in accordance with then-applicable State and Federal
requirements. 53 Fed.Reg. 25449.
On the question of whether existing State and Federal regulatory programs were
adequate, EPA concluded that there were gaps in the existing programs but that they
could be corrected without regulating oil and gas wastes under Subtitle C of RCRA.
State and Federal regulatory programs are generally adequate
for controlling oil, gas, and geothermal wastes. Regulatory gaps in the
Clean Water Act and UIC program are already being addressed, and
the remaining gaps in State and Federal regulatory programs can be
effectively addressed by formulating requirements under Subtitle D of
RCRA [the nonhazardous waste requirements] and by working with
the States.
53 FR 25447.
With respect to the third issue, EPA concluded that “For the nation as a whole,
regulation of all oil and gas field wastes under unmodified Subtitle C of RCRA would
have a substantial impact on the U.S. economy” 53 Fed.Reg. 25453.
Considering all the factors, EPA concluded that “regulation of all crude oil and
natural gas wastes under RCRA Subtitle C is unnecessary and impractical. The
Agency believes that these wastes can be managed in a manner so as to protect
human health and the environment without regulating them under RCRA Subtitle C.”
53 Fed.Reg. 25453.
Looking at the situation in 2014, we note that some flowback and produced water
from HVHF contain some constituents at greater than 100 times drinking water
standards. If the exemption were not in place, it is possible that these wastes would
qualify as hazardous. When these wastes are mismanaged, they have the potential to
cause damage. The Departments believe, however, that the deficiencies in the
regulatory programs of the 1980’s have been corrected, in particular with
regulations for landfills that receive non-hazardous industrial wastes. In Maryland,
specific waste management and disposal practices will be mandated for HVHF
wastes, if that activity is allowed in Maryland. Some of the practices common in the
1980’s, such as the use of reserve pits for drilling wastes; landspreading of reserve
pit contents; disposal of produced water in unlined pits; and discharge of produced
water to surface water, will be specifically prohibited.
As a practical matter, if Maryland were to eliminate the exemption, and some wastes
generated exhibited a hazardous characteristic, the wastes would be considered
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exempt again as soon as they left Maryland. Maryland’s action would not have any
effect on the way the wastes were ultimately treated or disposed of in another state.
There is a legal consideration as well. If the exemption were eliminated, the persons
generating the wastes would have to determine whether the wastes exhibit one of the
four characteristics that cause a waste to be classified as a hazardous waste. While
some HVHF wastewaters might exhibit the Toxicity Characteristic, that characteristic
is measured by a specific test (the Toxicity Characteristic Leaching Procedure
(TCLP), test Method 1311 in “Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,” EPA Publication SW-846) that is meant to simulate the
behavior of waste when it is co-disposing with municipal refuse or other types of
biodegradable organic waste in a sanitary landfill. Because flowback and produced
water are never managed this way, it is questionable whether application of a TCLP
test to classify a waste as hazardous could withstand legal challenge.
RISK ASSESSMENTS
1. Best practices cannot be established without first performing a risk assessment.
Until these risks are thoroughly studied, any attempts to set regulations for
fracking are premature. Your “Best Management Practices” report on fracking in
Maryland fails to adequately address the full scale and severity of these risks. The
report puts the cart before the horse since the state has yet to even begin a
thorough analysis of the unique risks of drilling in Maryland. Without this risk
analysis, the state is moving blindly in developing “best practices.”
One cannot evaluate a risk without having a fairly specific understanding of how the
activity will be carried out, and with what safeguards. Best practices and risk
assessment can be thought of as iterative processes: if an activity conducted using
best practices still poses a significant risk of harm, further safeguards or mitigation
measures can be considered.
Dr. Eshleman was asked to identify practices that would protect air quality; isolate
the gas well from the surrounding formations, including aquifers; protect water
resources from contamination, degradation and depletion; protect terrestrial habitat
and wildlife; protect aquatic habitat, wildlife, and biodiversity; protect public safety;
protect cultural, historical, and recreational resources; protect quality of life and
aesthetic values; and protect agriculture and grazing. Therefore, the scope of work
for the best practices study was developed with an understanding of the risks.
Even though the Executive Order does not require a risk assessment, the Departments
are undertaking a qualitative risk assessment. It will inform the findings and
recommendations on whether and how hydraulic fracturing can be done in Maryland
without unacceptable risks.
2. As fracking has occurred in neighboring states, concerns about harm to water, air
quality, health, and local economies have increased. I believe these potential
impacts must be weighed closely against the benefits these operations offer to the
LOCAL economy.
The State is undertaking a qualitative risk assessment, and has commissioned an
economic study to assess the potential positive and negative effects Marcellus Shale
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drilling. All of these issues will be considered in the final report. A public health
study is also being conducted to specifically focus on the public health implications of
unconventional gas well development.
3. I do not believe that it is possible to know how to minimize the impact to sensitive
resources, without first fully understanding the specifics and the magnitude of the
impact.
The State is undertaking a qualitative risk assessment that will consider the
probability of adverse impacts and the magnitude of the impacts.
4. Fracking uses immense amounts of fresh water which is irreplaceable, and that
effect occurs even when other damage might (or might not) be successfully
minimized.
Both surface and groundwater withdrawals will be considered during the qualitative
risk assessment planned by the Departments. Also the Department of the
Environment believes that current appropriation regulations found in COMAR
26.17.06.05 are adequate to address water withdrawals associated with Marcellus
shale gas drilling.
5. Spend and/or acquire the funding to do a comprehensive Risk Assessment.
Identify any data gaps in the BMPs, issue requests for studies to complete those
missing components, complete all of the other studies and then inform the BMPs
from those studies.
The Departments are undertaking a qualitative risk assessment for Marcellus shale
gas drilling activities in Maryland. The risks will be evaluated assuming the
recommended best practices are adopted. If there are high risks, the Departments
will consider whether additional best management practices could reduce the risks.
6. The CGDP section mentions mitigation in several places but fails to mention or
recognize that mitigation is an integral part of the risk analysis process in which
activities that have high risk are addressed by risk management alternatives to
address mitigation as well as alternatives that will lower a risk. We believe that
the Departments must not circumvent details for critical planning, siting, and
environmental assessment needed for the large landscape level development
plans.
The risks will be evaluated as if the recommended best practices have been adopted.
The Departments will consider additional practices and mitigation for high risk
activities.
SPREAD OF FRACTURES
1. Upward propagation of fractures.
The technique of hydraulic fracturing enhances the permeability of the host rock
so that the trapped resident gas can be released to the land surface. When the
fracking fluid is depressurized, solid-particle proppants, which were introduced
along with the fracking fluid, remain behind to keep the fractures propped open,
which maintains the immensely enhanced permeability.
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The disciplines of Geomechanics and Geohydraulics are central to understanding
and predicting the initial hydraulic generation and propagation of fractures within
the host rock. Multiphase Flow is central to understanding the initial inrushing
movement of the proppants and the subsequent non-movement of proppants in
response to depressurization within the newly formed fractures. Aquifer
Mechanics is central to predicting the gradual upward migration of zones of
enhanced permeability that will bring methane and possibly other contaminants
into the overlying freshwater aquifers. These hydro-geo-mechanisms could
result in seismic events and the introduction of chemical pollutants. In this view,
hydrofracking wells inherently function as injection wells. The initial response of
the subsurface geologic beds to quantifiable injection stresses would be identical.
The likely time-delayed deformational effects on overlying aquifers must be
addressed whether the wells inject waste materials in Pennsylvania that are
collected at a well site in Maryland or, even more drastically from the mechanics
point of view, whether the Maryland wells simply inject water, proppants, and
undisclosed chemical additives within a concurrently expanding and extending
new fracture at depth.
The gradual upward migration of newly formed fractures in massive rock and the
correlated upward migration of zones of enhanced permeability in saturated
particulate-based beds such as aquifers, should be considered. Laboratory tests
indicate unequivocally that any slight change of porosity of particulate-based
aquifers (sand, clay, sandstone, claystone, etc.) changes the corresponding
permeability exponentially. This enhancement, in turn, directly affects the
upward density flow of gas into and through any aquifer towards the land surface
and into the overlying atmosphere.
Aquifer mechanics and the upward migration of fractures have been studied,
measured, and modeled in the American southwest. This is because such features
and their results are more observable in arid regions. The water table is often
hundreds to thousands of feet below land surface and an upward migration of a
crack can be identified through the brittle unsaturated overburden. Initially, arid
zone hydrogeologists borrowed concepts and equations from the mining industry
who appropriately use a bending beam analogy. But a crack in a bending beam
that is applicable to underground mines migrates from the top downwards,
contrary to hydrogeological observations in the field. These same mechanisms,
empirically corroborated in the American southwest, are applicable to hydraulic
fracturing anywhere and to the likely unavoidable gradual upward migration of
these fractures, especially when proppants remain in place.
It is important that the required microseismic and tiltmeter data gathered early at
each well be made available to State authorities, MDE, MDNR, the academic
community, and to the general public, along with any interpretations.
While gathering this microseismic and tiltmeter data, the operator can use other
early data in order to determine the principal directions of in situ regional stresses
at MDE and MDNR designated locales of interest. Such a determination can be
made by the operator from a well-known standard procedure while inducing an
initial or a more modest pre-initial hydraulic fracture. This information will help
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greatly to map in advance the direction of fracture propagation induced from any
specified horizontal line or vertical borehole. After reaching a reasonably short
distance from the borehole or line, the direction of propagation becomes
controlled by the pre-existing regional stress field.
There is a deafening silence in Maryland’s Best Practices Report (Draft)
regarding the likely eventual contamination of fresh-water aquifers by the hydrogeo-mechanisms mentioned above. For example, Departmental Response 4-K (p.
F-10) says that consideration of underground injection wells is deferred because it
is not likely that any will be located in Maryland. Methane gas WILL enter the
drinking water. The only question is when, where, and at what rate. The answer
to this question is location specific. Polluting chemicals may well follow the gas.
The physical and chemical characteristics of these pollutants will determine if,
when, and where. The entirety of all horizontal lines are likely sources of
vertical-flow contamination.
The recommendation (Appendix F, Table of Recommendations 1-F) to analyze
groundwater flow by developing flow nets tacitly presumes unchanging flow
conditions and therefore is preliminary. We cannot estimate the response to
dynamic events (such as fracking events and also aquifer pumpage by county
residents) with static presuppositions. Depending on the available data, it might,
however, give a glimpse into the initial regional groundwater flow conditions and
directions. Such a glimpse is highly beneficial but is not sufficient. Changes to the
quality of water cannot be foreseen or forestalled if the directions and timings of
groundwater flow remain unknown and ignored even by the State. Actual
measurements and knowledge of already changed chemicals in the water are
necessary, but such knowledge may be too late to affect a timely response.
Aquifer amelioration, if possible, in response to such knowledge may be too
expensive. Accurate and informed modeling of future changing flow patterns is
not only critical, it is cheaper.
Assuming a statically safe buffer zone is questionable. Changes in the vertical
permeability will occur and cannot be ignored. This occurrence is dynamic
because the changes migrate upward with time.
In order to hydrofrack in the first place, the water pressure had to have been larger
than the minimum in situ principal stress within the shale. Any induced fracture
whose interior tensile pressure is maintained at depth, whether by continuing to
inject new water (to maintain its interior hydraulic pressure) or by proppant-toproppant stresses, will continue to expand in the local direction of minimum
resistance. In order to accomplish this feat most easily and efficiently, the
fracture’s interior walls migrate upward rather than outward. In principle, such a
fracture will gradually increase its length forever.
A recent study (ongoing) by the National Energy Technology Laboratory (NETL)
for the Department of Energy (DOE) found that fractures in 1 in 8 wells had
traveled up to 1,800 feet beyond the well bore, and federal regulators have
accepted industry arguments that fractures may travel up to 2,000 feet.
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Dominion wrote in a filing before FERC that there is no proven model or
technology that can accurately predict the location and extent of encroachment
of a hydraulically fractured shale well. The horizontal laterals may deviate
from the intended path trajectory.
The basic premise of these comments is that any fracture propagated in the shale will
continue to spread indefinitely in an upward direction, eventually reaching the
surface. The commenter cites a study published in 1994 that addressed the origin of
large surface cracks that formed as a result of groundwater withdrawal in Nevada.
The commenter postulates that the proppants that lodge in the induced fractures
supply a continuing force or stress that will cause the fractures to continue to grow in
an upward direction. The commenter also states that these growing fractures can act
as a pathway for vertical migration of methane and fracking fluids from the target
formation to drinking water aquifers.
Geologists from MDE, DNR and the USGS reviewed these comments and concluded
that it is unlikely that fractures induced in the Marcellus shale in Maryland would
continue to propagate to any great distance in an upward direction after the
hydraulic fracturing pressure is released to form a pathway for the migration of
methane or fracking fluid. Briefly stated, their reasons include:
i.
The circumstances leading to the appearance of surface cracks in Nevada, as
described in the 1994 paper, are not at all similar to Marcellus hydraulic
fracturing operations. Nevada is in the Great Basin, a geologic setting
characterized by extensional (pull-apart) tectonics. In such settings,
groundwater withdrawal from sedimentary aquifers results in land subsidence
and, sometimes, associated surface cracks, often located in proximity to
extensional faults. Western Maryland’s geology is dominated by hard,
lithified and fractured sedimentary rocks which have been tectonically
compressed. Groundwater withdrawal in Western Maryland is not known to
produce any surface cracks.
ii.
Hydraulic fractures form with an orientation perpendicular to the least
compressive stress. At depths less than 2,000 feet, the overburden is the least
principal stress, and if pressure is applied, fractures will preferentially form
in the horizontal plane. Within Garrett County and westernmost Allegany
County, the Marcellus is 5,000 to 9,000 feet deep. At these depths, the
dominant stress is the weight of the overburden pressing downward, and the
least principal stress is horizontal. Fractures induced at these depths will be
oriented vertically. The ideal fracture can be visualized as a knife blade
extending laterally straight out from the borehole with the cutting edge of the
knife straight up (or straight down). See diagram below. If the pressure
opens micro-fissures, micro-fractures and weak zones within the shale, it
creates a network of connected fractures that can be compared to the network
of cracks in shattered glass.
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Conceptual drawing of multi-well pads with additions
from Chairman David Vanko showing the orientation
of least compressive stress and the resulting shape
and orientation of induced fractures.
iii.
If a fracture were to reach a boundary where the principal stress direction
changes, the fracture would attempt to reorient itself perpendicular to the
direction of least stress. Therefore, if a fracture propagated from deeper to
shallower formations it would reorient itself from a vertical to a horizontal
pathway and spread sideways along the bedding planes of the rock strata.
iv.
In the Barnett shale, induced fractures appear to extend about 100 feet up and
200 feet down from the location where hydraulic fracturing pressure is
applied, but 600-800 feet to the left and right. See diagram below. Although
fractures have been mapped to extend upward as much as 2,000 feet in the
Marcellus shale, most fractures that have been mapped are significantly
shorter.
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Figures 4A and B from Addressing the Environmental
Risks from Shale Gas Development (2010), M. Zoback, S.
Kitasei, & B. Copithorne, Worldwatch Institute, Briefing
Paper 1. Each dot in Figure 4A and B represents a
microseismic event induced during hydraulic fracturing
of an actual well in the Barnett Shale, with each color
representing a distinct fracturing stage.
v.
The pressure of the fracking fluid opens the fractures. The pressure might be
applied for a period of a few minutes or a few hours. It will immediately
begin to decrease, however, as the fluid contacts more rock and the fracking
fluid leaks into permeable formations. When the pressure no longer exceeds
the pressure at which the rock will break, fracture growth will cease.
Proppants keep the fractures open when the pressure is fully released. Most
geologists would not expect the proppant to act as an additional stress that
would cause the fracture to continue to grow because there are other
phenomena that act to reduce the pressures and stop the fracture growth.
Shale contains clay that is somewhat plastic and could flex, reducing pressure
and stress. The fractures would be in communication with the perforated
casing in the horizontal borehole, and methane and formation water in the
fractures would enter the borehole, releasing additional pressure. Fractures
would stop if they reached rock more resistant to breaking than the shale.
And, as noted above, if a fracture propagated from deeper to shallower (less
than 2,000 feet deep) formations it would reorient itself from a vertical to a
horizontal pathway and spread sideways along the bedding planes of the rock
strata.
vi.
The period of high pressure operation is probably the only time most wells
will experience pressures high enough to cause fluid to flow into the
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formation. In normal circumstances, the methane, fracking fluid and water in
the formation, like other gases and fluids, tends to flow from an area of higher
pressure to lower pressure; that is, to flow from the formation into the
wellbore.
2.
Communication with existing fractures.
The CGDP will require more wells from a single pad and this may lead to closer
consolidation of well bores. Research shows that fractures created by fracking
“communicate,” or connect, with existing fractures, which can eventually reach
aquifers. Unfortunately, criteria for “setbacks” are applied only to the pad and to
other activities and events taking place at the land surface. These applications
are necessary, but are not sufficient. Though one can expect historic gas wells
(and environs) to mark locations where vertical upward flow of gas and
pollutants may occur, they do not mark the only locations where one can expect
to find sooner or later zones of enhanced vertical permeability that eventually
will reach the land surface and hence will introduce future upward flow of
methane gas not only to fresh water aquifers and wetlands, but also to the
atmosphere. One should also consider the effect that formation-to-formation
geologic heterogeneities have on the mapping of where zones of enhanced
permeability may be expected to migrate. Ditto for the locations and geometries
of deep coal mines. Maryland is encouraging drillers to place well pads close
together to protect the land, but will their proximity lead to unforeseen problems
involving existing fractures?
Communication between induced fractures and the surface (or freshwater aquifer) is
not expected to occur unless the induced fractures reach a discontinuity in the
various strata that separate the Marcellus from the shallow groundwater aquifers.
Some of these discontinuities are known, such as the faulting around the Accident
Dome, and others are only suspected, for example, the cross-strike discontinuities
(Southworth, 1986). In these cases, the discontinuities have the potential to allow
migration along their joints. At this time, the exact location(s) of these faults and
discontinuities are not known in Western Maryland. Therefore, the Departments plan
to require as part of the Comprehensive Gas Development Plan (CGDP) that the
contractor perform geological investigations to identify any discontinuities in the
geologic structure throughout the entire depth and spatial extent of the CGDP
planning area. This information is to be transmitted to MDE and Maryland
Geological Survey.
Maryland geological experts have little concern with communication between other
induced fractures within the Marcellus as any communication between those
fractures does not create a pathway for upwards migration of contaminants or gas
into the freshwater aquifers.
3. Seismic survey requirements.
a. MDE scales back the seismic mapping requirements recommended by UMC
ES-AL, requiring only one test per well on the pad. If we are to permit pads
with up to 18 well bores, repeated fracturing of all these closely-clustered well
bores & laterals could result in seismic changes. MDE should require
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seismology of the area to be developed and identify the area or areas where
HVHF may communicate with naturally occurring geological faults.
b. It would be extremely beneficial to select key locations and to test at the field
scale if possible for the pre-fracturing vertical permeability of the geological
units of interest.
c. Microseismic and tiltmeter data should be gathered for each well. Once again
the UMCES-AL recommendations are being ignored. As work progresses and
wells are repeatedly fracked additional surveys should be required to monitor
subterranean conditions and prevent nasty surprises.
d. Environmental assessments (see Marcellus Safe Drilling Initiative Study: Part
2, Section V: Item 1) should include the determination of in situ principal
stresses and the mapping, specified location by specified location, of the most
likely direction(s) of uncontrolled future fracturing and enhanced
permeability.
Seismic surveys and other geologic investigations will occur at two different times
during any unconventional gas well development. Before any production gas wells
are developed, companies will be conducting geologic investigations and possibly
developing exploratory wells across the landscape proposed for gas development to
assess/target extraction efforts. As indicated in the response to comment 2, the broad
scale three dimensional geologic investigations, which would include seismic surveys,
will be required for the CGDP application in order to identify existing faults and
discontinuities and guide the siting of well pads.
Once the well pad site is selected, additional geologic investigations will be made
with the first pilot hole to determine the density, extent, and direction of existing
fractures, voids and other necessary geologic information along its entire depth.
Microseismic, tiltmeter and other analytical survey approaches may be used singly,
or in combination, to provide the required data. The geologic studies at the scale of
the pilot hole are required to assess the geology in the vicinity of the well site and
pad. The Departments are satisfied that one geological study per well pad is
sufficient to fully characterize the local geologic conditions.
The UMCES-AL study recommended that a sufficient number of micro-seismic or
tiltmeter surveys be done to characterize the extent, geometry and location of
Marcellus fracturing across the region; but the study did not identify how many
would be necessary. Citing API Guidance Document HF1, First Edition, the
UMCES-AL study also noted: “Best practice is not to employ tiltmeter surveys or
microseismic on every well, rather it is most commonly used to evaluate new
techniques, refine the effectiveness of fracturing in new areas or formations, and in
calibrating computer models of the fracturing process.” The draft best practices
report recommended requiring that the operator perform a tiltmeter or microseismic
survey on the first well hydraulically fractured on each pad. We believe that a
microseismic or tiltmeter testing on the first well of each pad will provide the data
necessary to understand the regional characteristics of the Marcellus Shale;
however, MDE has the authority to require such testing on each well through the
individual permit. Such a requirement might be appropriate if the first hydraulic
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fracturing resulted in fractures that extended far beyond the target formation, or if
the operator proposed to use a significantly different hydraulic fracturing regimen on
subsequent wells. Because Maryland will require that all information collected at the
site be submitted to the State, the results of any additional microseismic or tiltmeter
testing will be available for use in further refining our understanding of the formation
and the extent of fractures.
As detailed in the response to comment 1 above, Maryland’s geological experts do
not concur there will be uncontrolled fracturing due to the mechanisms described in
that response.
4. Open hole logging requirements.
Safe Drilling Initiative Study: Part 2, Section VI, Section E, Item 5g. The
statement is too weak. An experienced and intelligent driller has probably
developed his or her own seat-of-the-pants method of estimating answers to (a)
through (f) and may be good at it. If these logs are desired, they should be
required.
The well permit, if issued, will contain requirements for logging the borehole. The
required information, especially for items such as the depth at which any fresh water
is encountered, must be reliably measured. Current Maryland regulations require the
submission of these logs as a component of the well completion report.
5. Long term monitoring and protection from methane migration.
Safe Drilling Initiative Study: Part 2, Section VI, Section R (Closure and
Reclamation). Responsibility and monitoring of gas and chemical contamination
of aquifers should continue for three to five decades after decommissioning of the
well. The burden of scientific proof and empirical corroboration lies with the gas
company to demonstrate that aquifer pollution will NOT occur over the next
several decades due to the gradual upward migration of permeability
enhancement. Opinion or poor physics cannot be tolerated or excused. This
should also be considered when setting terms of financial bonds.
The most likely route of methane migration or other contaminants to water supplies
(as determined from review of case studies throughout the U.S.) is from improper
well casing/cementing and/or leakage of fracking fluid waste pits, not through spread
of fractures (see response to comment 1) or fracture communication with existing
wells or faults. As a result, Maryland will require practices to prevent contamination
from occurring and provide financial assurance/insurance coverage to address
contamination events. These include:
i.
Presumptive Impacts Areas - Environment Article §14-110.1 incorporates a
presumptive impact area where any contamination of a water supply within
2,500 feet of a gas well will assume gas exploration/production as the cause;
ii.
Proposed Best Management Practices to Prevent Surface Contamination –
prohibiting storage of fracking fluids in surface pits (must be in tanks with
secondary containment), requiring closed loop systems for drilling and
cutting, and requiring no-discharge well pads to capture any spills that may
result from tanks or closed loop systems;
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iii.
Proposed Best Management Practices to Prevent Subsurface Contamination –
Requiring enhanced specifications for casing, cement cure times, and
minimum compressive strength standards for cements;
iv.
Currently Required Permits or Practices – Mandatory well completion
reports to identify extent of groundwater resources, oil and gas resources
encountered during drilling, total well depth, general geology/lithology, depth
of salt water, and other generalized core descriptions. Further, permits
require that environmental liability insurance be maintained for 5 years after
MDE has determined that a gas well has been properly plugged and the site
has been reclaimed.
The Departments’ position is that the combination of these requirements provides
more than sufficient preventive and remedial measures to address contamination
resulting from natural gas extraction. The Departments disagree with the comment
that “gradual upward migration of permeability enhancement” is a justification for
monitoring decades after a well has been decommissioned.
6. Freshwater 2000 foot vertical separation.
Safe Drilling Initiative Study: Part 2, Appendix D 1-H, states “Since the
freshwater/saltwater interface has not been mapped in Maryland, the prudent
approach would be to rely on the 2,000 ft criterion to provide an adequate margin
of safety.” Specifying vertical depth offsets presumes that the physical
characteristics of geological units remain unchanged. Assuming such a statically
safe buffer zone is questionable. Changes in the vertical permeability will occur
and cannot be ignored. This occurrence is dynamic because the changes migrate
upward with time.
Evidence indicates that a vertical separation of the order of 2,000 feet would result in
a remote risk that properly injected fluid would result in contamination of fresh
groundwater. Having the default 2,000 foot vertical separation will not preclude the
Department of the Environment from requiring greater vertical separation, where
appropriate. Comprehensive information gathered during the environmental
assessment, during pilot and exploratory well drilling, and collected from seismic
tests will be used to determine if additional separation is required for an individual
well to address site-specific geological factors.
7. Presence of historic gas wells.
The Environmental Working Group’s extensive study found that the horizontal
fractures can extend over 2,000 feet and fracture older gas wells that may not be
identified and sealed and then create a perfect path for chemical and methane
migration into aquifers.
Responses to comments 1 and 6 address questions regarding upward propagation of
fractures and vertical separation from aquifers. The Departments recommend a
1,320 foot setback from historic gas wells to any portion of the borehole, including
laterals. Locations of known historic gas wells will be provided through the Shale
Gas Development Toolbox to support the siting of well pads through the CGDP. As
with other fine scale features or features that do not have comprehensive mapping
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completed, such as small wetlands and headwater streams, the applicant will be
required to perform site assessments to identify any unmapped historic gas wells
within the setback zone.
STORMWATER MANAGEMENT
1. The well pad, according to the BMPs, would have to be surrounded by a berm
designed to hold at least 2.7 inches of rain within a 24-hour period, so that spills
of gasoline, oils and other hazardous chemicals wouldn’t flow onto surrounding
land. Maryland weather records show more than that amount of rain has fallen in
24 hours on several occasions in the past few years, including during Superstorm
Sandy. Climate change guarantees more deluges, so this BMP is not sufficient to
protect the land, water, human health or wildlife.
The draft report proposed that no discharge of stormwater from the pad would be
allowed as long as there were any chemicals onsite, and set a minimum containment
amount at 2.7 inches in a 24 hour period. Regardless of the number of inches chosen,
there will inevitably be precipitation events that exceed the amount. If there were
more precipitation than the containment could hold, the operator would need to
remove collected stormwater for storage and proper disposal. Any discharge would
be a violation of the law. Nevertheless, the Departments are persuaded that
increasing the design to hold 4 inches of rain in a 24 hour period will provide
additional protection and is not unreasonable. The Departments will modify the
practice to require a minimum containment amount of 4 inches of rain in a 24 hour
period.
2. Please modify the draft regulations to handle 4" of rainfall within a 24 hour
period.
Agreed. This BMP will be modified to 4 inches.
3. BMPs to address storm water management and erosion control must be extremely
comprehensive and innovative. BMPs should also be more expansive and address
short- and long-term (legacy) issues.
In addition to the requirement to contain all stormwater on the pad while chemicals
remain onsite, the State sediment and erosion control and stormwater management
laws and regulations apply to these drilling operations. Proper reclamation of the
site will address legacy issues.
4. No discharge of potentially contaminated stormwater or pollutants from the pad
shall be allowed and must be enforced.
The Departments agree and the draft report reflects this requirement. Any discharge
would be a violation of the law and enforced appropriately.
5. The linear nature of pipelines and the amount of clearing, grading and trenching
involved makes pipelines a potential significant source of sediment pollution
during the construction phase. Unfortunately, the BMP report is silent on how the
Departments plan to handle stormwater runoff from pipelines, access roads, and
other construction activity. We recommend that limits be placed on the length of
open trench and non-stabilized soil exposed at any time. Pipelines rights of way
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should be cleared, pipe laid, filled, and stabilized in segments to avoid excessive
erosion. In addition, the right of way should be vegetated within an appropriate
timeframe.
The State erosion and sediment control regulations would apply to these pipeline
projects and specify that only 20 acres can be disturbed at any time and requires that
all perimeter controls (e.g., earthen berms, sediment traps) and slopes steeper than
3:1 must be stabilized within three calendar days and all other disturbed areas within
seven calendar days.
6. The Departments should make a determination whether the “hotspot” designation
would provide better stormwater management protection than what is otherwise
contemplated by the BMP Report. Hydraulic fracturing operations should be
treated the same as similar heavy industrial activity.
In the judgment of the Departments, designation of the pad as a “hotspot” would not
afford any better protection than the recommended BMPs. The BMPs could be
incorporated into the well permit. Because the well permit must be renewed
periodically and stay in effect until the well is properly abandoned, this will provide
protection during the lifetime of the well.
7. The requirement to capture, store and transport all storm water can result in a
large increase in truck traffic to haul the storm water from the entire pad.
Capturing and storing only that water which could potentially be contaminated
would be an adequate approach to meet the environmental safeguards sought
without unnecessarily increasing truck traffic. Establishing a clearer definition of
what constitutes a “drilling pad” could also be helpful. Potential contamination
sources would be the drilling rig and associated equipment, excluding areas
occupied by temporary housing, parking lots, etc.
In establishing the BMPs for stormwater, the Departments made the assumption that
all stormwater that collects on the pad could potentially be contaminated by contact
with equipment, fuel or chemicals. If the operator collected stormwater in
aboveground tanks, it could be used for hydraulic fracturing.
The Departments will define the “drilling pad” to include that area where drill rigs,
pumps, engines, generators, mixers and similar equipment, fuel, pipes and chemicals
are located. The definition will exclude temporary housing and employee parking
lots.
8. Require gas companies to complete Storm Water Pollution Prevention Plans that
severely limit toxic run off and erosion.
This was included in the draft report.
9. Require gas companies to complete Storm Water Pollution Prevention Plans that
completely contain toxic run off and erosion. No "mitigation" or "minimization"
weasel-wording.
See above.
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STRINGENCY OF THE PROPOSED BEST PRACTICES
1. The recommended best practices are unjustified, too stringent and too onerous.
a. The Governor's call for a "Gold Standard" has Maryland proposing the
strictest set of drilling requirements in the United States. But in its effort to
propose the strongest standards, the State has drafted its own Best
Practices, a number of which are not required by any other state or a
voluntary consensus Industry standard and that, if adopted, may not allow
for reasonable development. While learning from other states or Industry
experiences makes sense, creating an untested Best Practice in a vacuum
does not.
b. Maryland should leverage the best practices from other states deeply
involved in fracking.
c. These are excessive requirements that are more stringent than those in
neighboring states:
i. High financial assurance requirements, including a periodic
updating of closure cost estimates.
ii. Closed-loop drilling
iii. Zero discharge pads
iv. Prohibition of impoundments for anything except fresh water
v. On-site management of flowback and produced water
vi. Mandatory chemical disclosure that does not protect proprietary
trade secret information.
d. The Practices recommendation was undertaken pursuant to an Executive
Order directing a study to include recommendations for best practices for
all aspects of natural gas exploration and production in the Marcellus
Shale in Maryland. A popular definition of a best practice defines it as the
"best way to do something; the most effective or efficient method of
achieving an objective or completing a task." [Bing Dictionary]. By
focusing primarily on the environmental science report and largely
ignoring industry recommendations for the most efficient and effective
means of production, the Practices recommendations fail to fulfill the
stated purposes.
e. The intention of the BMPs should be to protect human and environmental
health, however, the research has not been done to provide a scientific
basis for these practices.
f. Our biggest concern lies with the process of the Comprehensive Gas
Development Plan. With only approximately 1 percent of the shale play
lying in our area and Dr. Eshleman’s report recommending that this type
of plan be voluntary, the proposed regulations are too time consuming and
expensive compared to our neighboring states. In my view, this
discourages the entry of multiple companies into the Maryland fields and
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at this point has completely run the gas companies “out of town” so far as
considering leases or development of wells. It may be an unintentional
consequence, but this limits competition and works to the disadvantage of
all. I do not quite understand how the effort to develop an oversight
process turned into a focus of creating a “gold standard” that makes
Maryland regulations more stringent than any other state in the nation.
Governor O’Malley’s Executive Order establishing the Marcellus Shale Safe Drilling
Initiative acknowledged that there were potential benefits and risks of damage from
gas extraction. The Departments have attempted to identify feasible practices that
are likely to protect public health, safety, the environment and natural resources if
the Administration chooses to move forward with Marcellus Shale drilling. The
suggestion that reports released thus far have been done in a vacuum is not the case.
The State considered the regulations of other states and industry consensus
standards. The draft report recommended that applicants, in preparing the plan for
the individual well, “consider API Standards and Guidance Documents, and, if the
plan fails to follow a normative element of a relevant API standard, the plan must
explain why and demonstrate that the plan is at least as protective as the normative
element.” In addition, the Departments have considered the new laws and regulations
that have been enacted in other states. Some of the proposed best practices that
seemed innovative are now the law in these other states.
The financial assurance requirements were recommended by the Departments and the
Advisory Commission and passed by the Maryland legislature in 2013. The periodic
updating of closure cost estimates is necessary because there has been so little
experience with the actual costs of closing Marcellus shale wells. Closed-loop
drilling has become common in Marcellus shale states, as have improved
management of flowback and produced water. The draft report included the
recommendation that at least 90 percent of the flowback and produced water be
recycled on the pad where it is generated, but allows for alternative management if
this is not practicable. Zero discharge pads and prohibiting the use of impoundments
for wastes and wastewater offer an increased level of protection from contamination
of ground water and surface water. The chemical disclosure recommendation was
designed to protect trade secrets while giving those with a legitimate need access to
chemical information.
The definition of best practices in the Executive Order is “methods and techniques
that have consistently shown results superior to those achieved by other means, and
which are used as benchmarks.” In the context of the Executive Order, it is clear that
the desired result is not to identify “the most efficient and effective means of
production” but rather to determine what practices could reduce risks to reasonable
levels. At the same time, the Departments did consider the practical feasibility of the
recommended practices. The best available science was used as a basis for the
practices that are designed to protect human and environmental health.
The mission of the Maryland Department of the Environment is to protect and restore
the quality of Maryland’s air, water, and land resources, while fostering smart
growth, economic development, healthy and safe communities, and quality
environmental education for the benefit of the environment, public health, and future
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generations. The Department of Natural Resources leads Maryland in securing a
sustainable future for our environment, society, and economy by preserving,
protecting, restoring, and enhancing the State’s natural resources. The intent of the
recommended best practices is to support both missions.
2. The recommended practices are too costly. As we continue the effort to define
the balance between the rights of property owners and the protection of the
environment, the accountability of state officials to oversee the regulatory side of
the equation with a timely and balanced approach is a major concern. Of all of the
studies that have been ordered, I don’t believe I have seen a calculation of what
the cost of existing regulations for any kind of development already on the books
amounts to with the gas industry, much less the cost of all the newly proposed
regulations that are being proposed (such as the CGDP). It is a simplification to
just say that these are “gas company costs.” Every cent eventually leads to a
reduction to the property owner, which in turn is a reduction to our communities
and the state in taxes that will be paid.
Most of the recommended best practices have been adopted by one or more states or
are already used by the industry to prevent environmental and public health impacts
resulting from substandard practices. Comprehensive Gas Development Planning at
a landscape level has been used on a voluntary basis elsewhere and is one of the few
practices that can address cumulative impacts of gas development.
3. The recommended best practices will unreasonably delay drilling in Maryland.
a. The net result of these recommendations will reduce any interest in shale
gas production in Maryland because they are so stringent and timeconsuming, especially the CGDP and the two years of baseline
monitoring. Unless the Commission establishes a shorter and more
realistic time frame, drilling will be delayed while we are seeking to
expand upon economic opportunities and diversity through job and
industry growth.
b. Although the environmental study suggested voluntary plans, the Practices
require a mandatory plan, thereby adding an additional, time consuming
and expensive planning requirement to review locations of all
contemplated facilities intended by a prospective driller who may not yet
even have obtained the leases, options, rights-of-way and other property
rights. Besides the huge preparation difficulties, this requirement also
lacks defined standards of review and allows approval/disapproval
virtually at the discretion of the "State" (presumably meaning MDE). In
addition, the process of plan reviews is to include a complex process of
State review, local government review, stakeholder comments and public
comments following a public meeting. Then, the approval/disapproval
decision would probably be appealable to a court in a de novo proceeding.
Although there are some benefits to such a plan in coordination and siting,
these can be accomplished by a regulation in regard to pooling and siting
of facilities, without the addition of an entire pre-development level of
planning reviews, hearings and potential litigation.
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c. As an overall view of the recommendations from the document, this
appears to be geared toward requiring a great deal of initial reporting from
the operator to identify all of the future plans for drilling and production in
Maryland prior to any exploration drilling. The processes outlined require
considerable reliance on state agencies developing protocols, plans, and
toolboxes that currently do not exist. Coupled with requirements for
extensive multiple-year testing prior to the initiation of drilling, if an
operator worked diligently to drill an exploratory well in Maryland today,
these draft requirements and recommendations would put the well spud
date at minimum of five to six years into the future, assuming the state
develops the maps and protocols within one year of approval of the final
report, a goal that would prove challenging to achieve. Our organization
believes that a realistic and shorter time frame should be considered for
the combined CGDP and baseline activities (perhaps 12 months or less)
which would allow for exploratory wells to be drilled earlier in the process
to help provide more accurate and detailed information necessary for the
development of the CGDP.
d. An industry group estimates that, given the recommended processes, a
well operator will have to dedicate four years of resources and expense
before obtaining any information on the viability of production from the
Marcellus formations in Maryland. Given the choice of proceeding
through Maryland's cumbersome processes or dedicating resources
elsewhere, well operators will almost certainly choose to operate in other
states, further decreasing Maryland's economic competitiveness in this
arena. A more realistic time frame should be considered.
e. After reviewing the content of the draft report I conclude that it will be
2020 or later before any drilling for natural gas can occur if all of the
recommendations are accepted to create the "GOLD STANDARD" in
Maryland. Permits are being processed and drilling is taking place in our
neighboring states. The process to get a drilling permit in our neighboring
states and other states in the Union takes weeks or months, certainly less
than a year.
f. We have waited long enough. We see drilling all around Garrett County
and we are not allowed to take advantage of it. Reasonable controls are
appropriate. The proposed requirements are too restrictive and designed to
slow or stop drilling. PA WV seems to do ok. Let’s not reinvent the wheel.
Follow their experience and parallel their regulation.
g. No justification is identified for the imposition of predevelopment data
collection, which will be lengthy and expensive data collection and
reporting requirement. The effect is to add an additional two (2) years on
top of the potential two to four year period required to obtain an approved
Comprehensive Plan before application for a specific drilling permit.
Because an eventual drilling permit would be subject a review/appeal
process, there is the likelihood that the recommended Practices would
involve a five to seven year span before drilling could occur. Such
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Practices, in effect, would prolong the de facto moratorium on shale gas
drilling in Maryland.
h. We believe that some of the proposed mandates and testing requirements
including the CGDP are some of the most stringent regulations in the
Country but are also very costly and time consuming, while offering
minimal environmental protection. These recommendations rely upon
state protocols and plans that have yet to be established; or assessed for
practicality in real time applications. Therefore, we urge the commission
to seek shorter and more realistic timeframes to be considered for the
CGDP and allow the exploration for shale gas to be done earlier in the
process to provide for more accurate and detailed information for the
approval of the final CGDP. Please remember that we are competing
against other states for this economic activity while protecting our natural
resources.
i. There is a major risk that the numerous additional requirements suggested
in the draft Practices will have the effect of extending a de facto
moratorium on shale gas development in Maryland. We strongly
encourage rethinking and revision of the proposed Practices, to reduce the
burden of additional requirements wherever possible while retaining
reasonable protections for the environment.
j. We believe they go above-and-beyond what the Governor has called a
"Gold Standard" for drilling for natural gas. The permitting proposals
would add an increase in cost (upfront in particular), and the time
consuming process would make it extremely unlikely that any company
would be willing to meet all of these requirements, especially under the
present market conditions.
The Departments have tried to structure the best practices and the permitting process
in a way that balances the interests of the stakeholders. The CGDP is a broad-brush,
landscape level plan that, according to industry sources, is not very different from the
planning that industry does now. The Departments do not anticipate that this will
consume very much time. As proposed in the draft report, the CGDP review process
could be completed in less than six months. The two year monitoring period can
begin as soon as the CGDP is approved. For groundwater and especially for surface
water, the year-to-year variability can be large. Two years is a reasonable
compromise given inherent seasonal variability in environmental data.
Some elements of the Toolbox already exist, and more can be added in short order.
The Departments will be able to pull some protocols “off the shelf” and develop the
remaining protocols in a timely fashion.
The Departments have reviewed the regulations of other states so there was no need
to reinvent the wheel. Pennsylvania and West Virginia allowed drilling in the
Marcellus shale before updating their regulatory programs. Maryland hopes to learn
from their experiences. We are mindful of the competition that exists among states,
but Maryland wishes to avoid the damage that has occurred in some states because
the laws and regulations were inadequate or poorly enforced.
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It is also important to remember that other key economic engines in this region
(tourism and outdoor recreation) rely on the relatively rural and undeveloped
landscape. Allowing potentially large-scale industrial activity to proceed without
careful planning and incorporating lessons learned from other states jeopardizes the
viability and profitability of these other key industries. In the Departments’ view all
of the planning and best management practices proposed strike a fair balance
between the multiple stakeholders whose livelihoods depend on the natural resources
of the region.
4. The regulations deprive people of their property rights or violate the Constitution.
a. I am in favor of being allowed to drill for my gas and to take it to market.
As it stands now, my State government is blocking me from selling
property that I bought with hard earned dollars. I am extremely disturbed
by this action. I can still sell the timber from my land if I so choose, or
even a big rock, if someone wants to buy it. But not MY gas. Certain
people in our state are so concerned about drilling for this gas that it has
been, for all practical purposes, stopped / blocked.
b. A de facto taking occurs when government laws, regulations, or
restrictions in fact take your property because you can't use it. You've been
deprived of your property rights without being paid. My first question is:
Has or will the committee consider the cost to the State of Maryland if the
Courts were to determine that because of all the regulations and
restrictions imposed on natural gas drilling in Maryland, the result is a de
facto taking of property rights. (Natural Gas) Maryland seems intent on
setting an extremely high bar for the natural gas industry and setting
standards that are tougher than in any other state. Eminent Domain, the
governments taking of property, is ultimately a federal constitutional
question.
c. Can the State of Maryland under the Federal Constitution set a higher
standard for drilling than all the other states where natural gas
development is taking place? If the people of Garrett County with natural
gas rights had those same rights just across the line in West Virginia or
Pennsylvania, they could be worth a fortune. In Maryland those rights are
worth nothing, and they may never be worthy anything. How
constitutional is that?
d. I believe the MDE/DNR recommendations are more of a political
statement than based on good science, are excessive and unnecessarily
cause gas rights owners in Maryland extreme barriers to realizing value
from our land and minerals that we are granted by the Constitution of the
United States. These proposals are, once again, an attempt by those who
reside in areas where these natural resources do not exist, to impose their
preferences and beliefs on those of us who rightfully own these resources.
The question of whether a temporary moratorium or regulatory restrictions on
development constitute a taking without just compensation is a complex one and
beyond the scope of this response to comments. In general, a temporary moratorium
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for the purpose of developing comprehensive regulations is not a taking. Similarly,
regulatory restrictions that do not deprive a property owner of all reasonable use of
his property do not amount to an unconstitutional taking. The regulatory program
being developed under the Marcellus Shale Safe Drilling Initiative is not intended to
prevent gas development if it can be done without unreasonable risk.
States can and do enact laws and regulations that differ from each other without
violating the Constitution. The proposed best practices are based on the best science
available, not on political considerations.
5. The recommended best practices are unreasonably harsh compared to other
industries and risks.
a. How do the risks and regulation of drilling for gas compare to other things
that the government either allows or does little to stop?
i. The construction of windmills on ridgetops, with damage from the
site pads, access roads, and power line rights of way.
ii. The tons of salt used on highways each year, that damage water
wells, water sources, trout streams and forests.
iii. The wooly adelgid and red rust fungus are destroying out
hemlocks, which will damage trout streams.
b. The report portrays a very negative viewpoint toward the natural gas
industry. If every new applicant for permits to engage in any new
industrial development in Maryland was required to meet every stringent
requirement outlined in this report, there would undoubtedly be a
complete lack of interest by any person, firm or company to do business in
Maryland.
c. We consider the CGDP requirement to be above and beyond the standard
set for any other industries in Maryland and maintain that it will impair the
economic viability of the gas play. Therefore, we would like the
department to withdraw or completely revise the regulations regarding the
CGDP. We also feel that it should be voluntary, not mandatory, with
incentives to encourage companies to comply.
d. The magnitude of the effort to prevent drilling using the technique called
horizontal drilling and hydraulic fracturing until the report is completed
and recommendations adopted leads one to believe that there is a
presumption that this activity is much more destructive than any other
industrial activity that takes place in Maryland. No other industrial activity
in Maryland has ever been singled out for this degree of scrutiny. There
seems to be very little concern about the clear message that Maryland is
sending to those who would desire to do business in Maryland. The
message currently is simply that they are not welcome in this state. If all
of the recommendations of this study and report are implemented in law,
regulation, or permit conditions it is highly unlikely that any drilling will
occur in Maryland (at least in the foreseeable future). If it is the intent of
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those that commissioned the study to prevent the development of natural
gas in Maryland, then their mission has truly been accomplished.
e. For certain common activities, these proposed Best Practices would treat
the drilling industry differently than everyone else without any
justification. One example is the proposal for storm water management.
We strongly question with the present natural gas market, the sizable
acreage of leases not being renewed in Western Maryland, and these
overly stringent requirements whether there will be any significant
development of the Marcellus Shale in Maryland before 2020. This
proposal could result in a continuation of the de-facto drilling moratorium.
The draft BMPs and the potential "Gold Standard" for development only
mean something if they are balanced enough to allow drilling in Western
Maryland while offering sufficient protections to the environment and the
citizens of Maryland.
The Departments do not agree that the government fails to protect against the risks
posed by wind turbines, road salt and the wooly adelgid.
Wind turbines and shale gas development present some of the same risks of loss of
habitat and forest fragmentation. Wind turbines are permitted by the Maryland
Public Service Commission (PSC) by issuance of a Certificate of Public Convenience
and Necessity (CPCN). (Certain projects, if they do not exceed 70 megawatts, may
be exempt from the CPCN.) Other State agencies provide information and
recommendations to the PSC and there is a public process. Before a final decision on
the CPCN, the PSC must consider the effect of the generating station on, among other
things, air and water pollution and esthetics. The CPCN may impose conditions on
the project, such as an endangered species mitigation plan.
Road salt can cause adverse effects on water and land resources. Under § 8-602.1 of
the Transportation Article of the Maryland Code, adopted in 2010, MDE and SHA
are required to develop and annually update a Statewide Salt Management Plan to
minimize the adverse environmental impacts of road salt runoff. For counties and
municipalities it is expected that such plans be developed at the local level.
Maryland Department of Agriculture Forest Pest Specialists monitor the health and
vitality of forests in the region on a regular basis. Red Rust Fungus is not thought to
occur in Garrett County, but potential sightings should be reported to the MDA
Forest Pest Program. This fungus is not a threat to hemlock trees. It has been found
on growing stock in nurseries, but outbreaks in a natural setting are uncommon.
Additionally, the Maryland Department of Agriculture has a very active program for
suppression of Hemlock Wooly Adelgid, which includes insecticidal application and
biological control. Insecticidal application is one tree at a time with either soil
injection or trunk injection. This is extremely slow, but the Adelgid have not been
widespread in Garrett County until recently. Keeping forest along streams and rivers
is a priority on state lands, and set-backs, best management guidelines, and other
zoning protect privately owned forest along streams during logging and land clearing
operations.
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Gas production from horizontal drilling and hydraulic fracturing differs in scope and
magnitude from the conventional gas drilling that occurred in Maryland in the
twentieth century. It is also different from ordinary industrial activity in that it can
occur in remote rural settings and residential areas. It is reasonable to establish
regulatory standards before allowing it to occur. The best practices report considers
the risks posed by horizontal drilling and hydraulic fracturing. It does not assume
that the industry is more “destructive” than other industries.
The Departments believe that the stormwater management requirements are not
unduly stringent. Many facilities in Maryland are required to obtain a general permit
for the discharge of stormwater associated with industrial activity unless they can
make a “No Exposure Certification.” The oil and gas industry is exempt from this
permit requirement, but Maryland can include controls on stormwater under its gas
well permit.
6. The recommended best practices should be strengthened and too much deference
was paid to industry’s interests.
a. All permits should have a requirement that if more stringent regulations
are passed, the new regulations must be followed. Operations must be
shut down until the company can comply.
b. Regarding the constraint analysis, it is inappropriate for Maryland’s
agencies to develop regulations with the intention of maximizing
industry’s ability to recover resources under our communities.
The recommendations of BMPs in the report do not preclude the use or introduction
of new and innovative technologies. In some circumstances, new regulations are
immediately applicable or can be included when permits are renewed, a process that
occurs every five years. New regulations may also apply when a company replaces
or retrofits equipment. In other instances, particularly where complying with the new
regulations would require a company to retire facilities that have considerable useful
life remaining, it would be unfair to require immediate compliance. Lastly, regulated
businesses are usually given some time to comply with new regulations and are not
required to cease operations entirely.
The constraint analysis was performed to demonstrate that the setback requirements
and restrictions on location did not prevent the industry from accessing most of the
natural gas in the Marcellus shale in Maryland. It was not used to set the restrictions
or setback distances or to maximize industry’s ability to recover gas.
SURFACE IMPACTS AND SETBACKS
1. The activity will last a long time and will be disruptive.
a. Fracking is an industrial activity best confined to areas zoned for industry,
and the state should indicate so in the BMPs and eventual regulations.
b. Pads may be permanent or nearly permanent fixtures if the wells are
subject to enhanced gas recovery and then for geologic sequestration of
CO2.
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c. The noise, truck traffic and lights 24/7 are not only for thirty days as
industry would like the public to believe. Some well pads may have more
than one well, as many as 6-10, drilled in sequence. Companies may
continue with these wells for years. Completion may not happen in our
life-time.
d. In neighboring states, we have seen severe disruption to agriculture,
vegetation and to the topography.
e. The wells and wastewater sites desecrate beautiful natural landscapes and
deprive local flora and fauna of habitat.
f. How much buffer is enough to protect the water, air, and quality of life for
those living near such an industrial zone? Keep in mind that Garrett
County is currently a rural area of farms and forests. How will those who
live near these areas be compensated for these impacts? If compelled to
move due to the insults associated with this industrial zone who would buy
their homes and land? Remember, these are most likely people who have
not signed gas leases and who will not be receiving any royalties.
Counties and towns, not the State, have authority to zone. Under current law, MDE
must deny a permit if the applicant has failed to receive applicable permits or
approvals for the operation from all State and local regulatory units responsible for,
among other things, zoning. Current State regulations require the applicant to
produce written approval by the local zoning authority that all local planning and
zoning requirements have been met.
Pads may be permanent or nearly permanent, but the permanent pad will have a
lesser impact than a pad on which drilling and hydraulic fracturing is occurring.
Reclamation requirements would serve to reduce the size of the pad to the area
needed for gas production and well maintenance.
The Departments acknowledge that activity may occur on a single pad for several
consecutive months and may recur. The best practices are designed to limit the
impact of the activities under either circumstance. The Departments propose to limit
the hours of truck traffic to and from the well pad and place restrictions on the
initiation of drilling, fracturing or other activities in order to minimize impacts
during times of peak outdoor recreation or sensitive wildlife migratory or mating
seasons.
The best practices are designed to avoid severe disruption to agriculture, habitat,
flora and fauna. In addition to the CGDP, which will require consideration of
locations that avoid these impacts, there are specific protections against the
introduction of invasive species, light pollution, and noise pollution. The CGDP will
also reduce the impact on landscapes.
Buffers are one way to reduce or eliminate the impact of gas exploration and
production on neighboring properties and residents. Other best practices address
ways to reduce the sources and causes of those impacts and ensure that the site is
appropriately restored. If companies undertaking gas exploration or production
activities intentionally or negligently cause contamination, they would be liable for
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damages. The existing law specifically addresses liability for damage to water
sources within 2500 feet of a gas well. Other provisions require insurance so that
funds will be available for cleanup or to pay damages.
2. There should be a limit on the total amount of land that can be disturbed.
a. The Eshleman report recommended that gas drilling activities be limited to
only 1-2 percent of Maryland's land surface. This should be applied
throughout the State because gas-bearing shales are present in other places
in Maryland.
b. Mention is made “Avoid surface development beyond 2 percent of the
watershed area in high value watersheds. “ There is no “should” or “must”
associated with the stated threshold. MAC believes that a 2 percent surface
development on the Savage River watershed would have a huge impact
not only to the environment and streams that brook trout inhabit but also
to the natural setting and recreational experience that the watershed
provides.
c. The total disturbance limit to 2 percent on high value acreage should be
extended to all extraction zones. A different limit might be appropriate but
no limit is not reasonable.
d. The state will not require that multiple companies submit comprehensive
drilling plans together; rather, it will "encourage" them to work together
on drawing up their plans. Asking the gas industry to voluntarily work
together and share information about its drilling sites does nothing to
guarantee that the public's interest is taken into account during planning.
The recommendation of the UMCES-AL report that activities be limited to 1 to 2
percent of Maryland’s land surface has been widely misinterpreted. The actual
recommendation was that “Cumulative surface development (including all well pads,
access roads, public roads, etc.) could be maintained at less than 2 percent of the
watershed area in high-value watersheds.” UMCES-AL report at 6-14. The State
has limited land use authority; the authority to enact zoning, subdivision, and other
land use restrictions lies with the counties and municipalities. Nevertheless, the
Departments adopt this recommendation as a planning principle to be followed in the
CGDP and to be used as a performance measure. The recommendation was based on
empirical evidence that aquatic habitat and aquatic diversity become degraded by
stormwater runoff well before the percentage of impervious surface reaches
10 percent and that brook trout are almost never found in watersheds where
impervious surface exceeded 4 percent. The loss of some species, particularly stream
salamanders, can occur in watersheds with only 0.3 percent impervious surface. The
UMCES-AL research showed a relationship between the amount of impervious
surface in a watershed and degradation of the stream. In order to provide an
adequate margin of safety, UMCES recommended a 2 percent surface development
threshold which they note can be achieved through the sensible application of best
practices and comprehensive planning. The UMCES research relied in part on
studies and analysis provided by the Department of Natural Resources:
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
Fact Sheet: Impacts of Impervious Land Cover on Maryland Streams36

S.A. Stranko et al. 2008. Brook Trout Declines with Land Cover and
Temperature Changes in Maryland. North American Journal of Fisheries
Management 28: 1223-1232.37
The State and local governments take steps to protect all aquatic habitats from the
effect of stormwater runoff, including requiring stormwater management. The
Comprehensive Gas Development Plan will help limit the amount of surface
disturbance and direct it away from sensitive areas. The CGDP is mandatory for a
company, but it is not possible to compel companies to develop joint plans.
3. Some lands need more protection.
a. In general, we recommend inclusion---in the table and/or the
accompanying text---of the rationale for the specified setbacks. Some
appear arbitrary.
b. Proposed setbacks allow drilling 600 feet from “irreplaceable natural
areas” and “wildlands” and a mere 300 feet from a stream, river, spring,
wetland, pond, reservoir and 100-year floodplain. Drilling so close to
these fragile areas is unacceptable.
c. For aquatic habitat (riparian), the UMCES-AL Report cited recommended
varying setbacks based on biodiversity. The lowest setback was 330 feet
and the greatest was 1,240 feet (Table 5-2 and page 6-4). Why are the
Departments recommending a setback of 300 feet? Does the setback
provide adequate protection? Usually riparian areas are protected by
vegetated buffers. Will these buffer areas be factored into the setback
calculation?
d. Setbacks are distances in the BP Report from the well bore or well pad and
as mentioned in the setback table from the disturbed area to water supplies
or other important natural resources that need to be protected from
contamination, damage, view, or other object in need of separation. The
initial distances for state parks, scenic and wild rivers and for special
conservation areas (e.g., irreplaceable natural areas, wildlands) are grossly
inadequate and require reevaluation after a formal risk analysis has been
completed.
e. Include wildlands and all public lands under III.E.2.
f. Ecologically sensitive areas and irreplaceable habitats should be protected
from the adverse impacts of all aspects of gas and oil development and
supply, including drilling, pipelines, associated infrastructure and sand
mining; the high value habitats in Important Bird Areas should be
protected from industry activities.
g. The setbacks presented for the protection of scenic and wild rivers, special
conservation areas, is determined without consideration of methane
36
37
www.dnr.state.md.us/streams/pdfs/ImperviousFactSheet.pdf
http://clear.uconn.edu/projects/TMDL/library/papers/stranko_etal_2008.pdf
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migration via rock fractures well outside the limits collected from other
states and offered as "Best Practices". The suggestion that setbacks may be
expanded on a case by case basis merely suggests that the issue has not
been seriously considered.
h. A setback of 300 feet from aquatic habitat (defined as all streams, rivers,
seeps, springs, wetlands, lakes, ponds, reservoirs, and 100 year
floodplains) is not sufficient protection for waterways used by boaters and
fishermen. Drill pads should not be visible from a waterway or body of
water; disrupting river/reservoir use would have serious economic
consequences for tourism.
i. The Departments must use existing statute provisions (Md. Env. Code,
Section 14-108) to protect special and unique areas.
j. No CGDP plan or permits should be issued for fracking on public land.
k. A 300-foot setback on a body of water used by wildlife and for human
recreation is so small that the drill site would be visible from the
waterway; disrupting water use would have serious economic
consequences for the tourism sector, in addition to threatening wildlife,
especially endangered species.
l. As a watershed organization we know there are 18 mineral leases in the
DCL watershed. We are concerned that the setbacks for drilling are
insufficient to provide the protections needed within our watershed and in
the County.
m. A 300-foot setback for aquatic habitat, (all streams, rivers, seeps, springs,
wetlands, lakes, ponds, reservoirs and 100-yeat floodplains) is totally
inadequate as are a 600-foot setback for special conservation areas
(irreplaceable natural areas and wildlands) and 300 feet for all cultural and
historical sites, state and federal parks, trails, wildlife management areas,
scenic and wild rivers and scenic byways. Surface disturbance in areas
with sensitive resources should be limited to 3,000 feet.
n. 300 feet as a setback from historic sites would certainly destroy any
historical site or park. The industrial nature of a drilling operation is in
direct conflict with the goal of preserving cultural and historic or scenic
and wild byways. These unique resources need protection of at least 2000
feet if not much further.
o. There should be a setback from land on which MALPF holds an easement.
p. The setbacks from streams and rivers should be more than 300 feet –
maybe 1,000 feet from the drilling pad.
q. I live adjacent to a river canyon and can show you how and where a
simple tire track off the side of a road, can become a channel through
which rain finds its way to an underground spring or drainage field that
eventually finds its way to a creek and a river. I consider the 300 foot
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setback from waterways to be highly problematic and, I have to believe,
an arbitrary and uninformed criterion for ecosystem protection.
r. Greater setbacks for critical facilities such as hospitals, police and fire
stations should be considered. A hospital would be hard to evacuate if
needed. Police and fire stations will need to remain operable if there are
problems. Are there existing setback requirements from a cemetery?
The setback distances were established using the best available science and
information. For environmental setbacks, the habitat needs for sensitive species were
a key consideration. Common sense suggests that wider buffers should be more
protective of sensitive natural resource areas, although at some point the benefits of
buffer width extension may not increase further as buffer width increases. As an
example, the minimum buffer width recommendations for “Irreplaceable Natural
Areas” are based in part upon ecological factors, notably the optimal minimum
buffer width for forest interior-dwelling species (FIDS) and the minimum buffer for
forest canopy disturbance relating to the incursion of weeds and edge species.
The UMCES-AL report notes the results of studies of setbacks, but recommended
“minimum setbacks of 300 ft from floodplains, wetlands, seeps, vernal pools, streams,
or other surface water bodies.” Page 5-6. The Departments initially accepted this
recommendation. Based on the comments and additional research, the setback from
all streams, rivers, seeps, springs, wetlands, lakes, ponds, reservoirs, and 100 year
floodplains has been increased from 300 feet to 450 feet and addresses both water
quality and biodiversity protection.
In order to fine tune setbacks for lands important for providing outdoor recreational
uses, the Department of Natural Resources conducted a mapping workshop to identify
recreational areas that are intensively used in the Marcellus Shale areas of
Maryland. The locations of these areas will be mapped and included in the toolbox to
guide the preparation of a CGDP that will avoid conflicts with public use. Setbacks
may be expanded on a case by case basis, using, in part, the information collected
through the DNR participatory GIS workshops.
Although drill rigs may be visible to boaters and fishermen even with the setback
distance of 450 feet; completed well pads will not be as visually intrusive. Visual
mitigation measures, if appropriate, can be imposed suitable to the season and
activity. The long term visual impact of completed pads should not have a significant
impact on the tourism economy.
Wildlands and public lands will be mapped in the shale gas development toolbox.
The best practices are designed to protect ecologically sensitive areas and
irreplaceable habitat. The combination of protective setbacks and good planning
through the CGDP will also protect other high value resources, such as Important
Bird Areas (IBAs) because many of these areas are co-occurring. The CGDP will
help insure that the pad, wells and infrastructure avoid these areas. Sand mining is
not addressed through these best practices recommendations because it falls under a
separate permit program.
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Methane migration is addressed through best practices and methane leaks will be
addressed through a leak detection and repair program.
Section 14-107 of the Environment Article of the Maryland Code establishes a
blanket prohibition against drilling for oil or gas in the waters of the Chesapeake
Bay, any of its tributaries, or in the Chesapeake Bay Critical Area. In contrast,
Section 14-108 deals with individual permit applications and requires MDE to deny a
permit if it determines that proposed drilling or well operation poses a substantial
threat to public safety or a risk of significant adverse environmental impact to (i) The
Chesapeake Bay; (ii) The Chesapeake Bay Critical Area; (iii) Tidal or nontidal
wetlands; (iv) Endangered or threatened species, species in need of conservation, or
the habitat of any of them; (v) Historic properties under § 5A-326 of the State
Finance and Procurement Article; (vi) Populated areas; (vii) Freshwater, estuarine,
or marine fisheries; or (viii) Other significant natural resources. It also requires the
Department of the Environment to deny a permit if the proposed operation will
constitute a significant physical hazard to a neighboring dwelling unit, school,
church, hospital, commercial or industrial building, public road, or other public or
private property in existence at the time of the application for the permit; or if the
operation will have a significant adverse effect on the uses of a publicly owned park,
forest, or recreation area in existence at the time of the application for the permit.
Section 14-108 required consideration of the individual permit application, and will
be used as appropriate to protect these areas from substantial threats to public safety
or a risk of significant environmental harm.
As noted above, the recommended 300 foot setback from surface water has been
increased to 450 feet based on both water quality and biodiversity protection. A
blanket set back of 3,000 feet cannot be justified. The basis for requiring a setback
from MALPF-eased land is unclear. Setbacks are applied to public lands to minimize
the potential public use and recreational conflicts. These concerns are not applicable
to privately owned eased lands that are not supporting a public recreational use. The
presence of wildlife and the impact on public and private property, historic areas and
recreational areas can and will be considered during review of the CGDP and the
individual well application.
The setbacks for occupied buildings should be adequate for hospitals, police and fire
stations. In addition, as noted above, Section 14-108 of the Environmental Article of
the Maryland Code also requires the Department of the Environment to deny a permit
if the proposed operation will constitute a significant physical hazard to a
neighboring dwelling unit, school, church, hospital, commercial or industrial
building, public road, or other public or private property in existence at the time of
the application for the permit. There are no setback requirements specific to
cemeteries.
4. Public and private wells should be protected by equal setbacks.
a. Under the proposed BMPs, the drill rig can be as close as 1,000 feet from
an occupied building (house, school, medical office, store), 1,000 feet
from a private well and 2,000 from public groundwater wells or surface
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water intakes and reservoirs. We do not think private wells and public
groundwater wells should be treated differently.
b. It is appalling and shameful to propose different setback standards for
municipal waters and for private wells.
c. The report proposes a setback of 2,000 feet for public water supplies but
only 1,000 feet for private wells. In essence, you are saying that safety and
health is not important for the few or if only a few families are adversely
affected.
d. The 2000’ public drinking water supply setback should also apply to
public drinking water tributary streams and impoundment borders.
The Departments are concerned about the health and safety of all Marylanders.
There are distinctions between public and private wells, however, that justify different
setbacks. Public wells generally draw water from a larger area than private wells,
making a larger distance appropriate. The Departments propose, however, to modify
the setbacks for drinking water protection as follows: a well pad cannot be located
a. Within 1,000 feet of a wellhead protection area or a source water
assessment area for a Public Water System38 (PWS) for which a Source
Water Protection Area39 (SWPA) has been delineated. [Note that a
similar setback is already in effect for wellhead protection areas.
COMAR 26.19.01.09G]
b. Within 1,000 feet of the default wellhead protection area for public water
systems for which a wellhead protection area has not been officially
delineated. [For public water systems that withdraw less than 10,000 gpd
from fractured rock aquifers the default SWPA is a fixed radius of 1000
feet around the water well(s).]
c. Within 2,000 feet of a private drinking water well; except that the well pad
may be located between 1,000 and 2,000 feet of a private drinking water
well if the applicant demonstrates through a hydrogeologic study that the
proposed well pad is not upgradient of the private drinking water well and
the owner of the private drinking water well agrees.
d. Within 450 feet of any other stream, river, seep, spring, lake, pond, or
reservoir from which drinking water is drawn.
e. Within the watersheds of any of the following reservoirs:
i. Broadford Lake
ii. Piney Reservoir
38
A public water system is a system for the provision to the public of water for human consumption through pipes or other constructed
conveyances, if such system has at least fifteen service connections or regularly serves at least twenty-five individuals. There are
three types of public water systems: community water systems, nontransient noncommunity water systems and transient
noncommunity water systems.
39
A Source Water Protection Area (SWPA) means an area delineated through Maryland’s source water assessment program for the
protection of a groundwater source (wellhead protection area) or a surface water source. For public water systems that withdraw less
than 10,000 gpd from fractured rock aquifers using, if a specific SWPA has not been delineated, the boundary shall be a fixed radius
of 1000 feet around the water well(s).
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iii. Savage Reservoir
The Departments continue to believe that a setback of 2,000 feet for public drinking
water system wells is appropriate. A 1,000 foot setback for private drinking water
wells is reasonably protective against surface spills if the proposed well pad is not
upgradient of the private drinking water well and the owner of the private drinking
water well agrees; otherwise, the setback from private drinking water shall be 2,000
feet.
Based on further consideration, the Departments have decided to establish a setback
specifically for springs that are the source of domestic drinking water to the residents
of the property on which the spring is located. The setback, measured from spring to
the edge of the well pad, shall extend to all lands at an elevation equal to or greater
than the spring discharge elevation, but not to exceed 2,500 feet unless a delineation
of the recharge area prepared by a registered geologist, with a report and data
supporting an alternate area, is submitted to the Department and the Department
approves an alternative area.
5. Setbacks of one to five kilometers should be adopted.
a. We recommend that all setbacks—whether from streams, springs, rivers,
wetlands, ponds, scenic byways, reservoirs, schools, homes or shops—be
at least 3,500 feet. (If the health study shows that even greater setbacks are
needed to protect residents and wildlife from air pollution, then these
setbacks will have to be revisited.) Proposed New York regulations call
for a buffer of 4,000 feet from “unfiltered surface drinking-water-supply
watersheds.” We recommend the state consider that distance as well. A
Duke University Study found that 82 percent of drinking water wells
monitored within a 5 kilometer radius of drill bore were likely to contain
stray methane. Of those, the wells within one kilometer (3280 feet) were
6 times more likely to contain stray methane. (report) University of
Texas Arlington has released a report establishing a 3 kilometer distance
of impact between drill pads and drinking water wells. This study was
similar to the Duke study that measured methane concentrations in
drinking water. The Texas study shows significant risk to drinking water
wells within 3 kilometers, not of methane contamination, but of metals,
including arsenic. Three kilometers is near the length of most horizontal
well-bores. The setbacks should be extended at least to 3300 feet.
b. The BMP report calls for 1,000 foot setbacks from water wells, and 2,000
feet from public water supplies. Since finding out that contamination can
occur when any fracked well is as far away as 3,280 feet. There was
another study that found different contaminants associated with fracking
within up to 5 miles of gas development. As it is not certain how far these
substances can migrate, setbacks need to be at the greatest distance
possible.
c. Setbacks for well pads and infrastructure from private and public water
wells, homes, schools, and office buildings should be at least 3,500 feet. A
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recent Duke study found methane in wells up to 1 kilometer away from
drilling sites.
d. The proposed 1000′ for private and 2000′ public drinking water setbacks
in the draft Best Management Practice are not enough. Proposed setbacks
allowing drilling 600 feet from “irreplaceable natural areas” and “wild
lands” and a mere 300 feet from a stream, river, spring, wetland, pond,
reservoir and 100-year floodplain is an unacceptable risk. Based on
evidence of methane, ethane, and propane contamination documented by
Duke University researchers, MDE and DNR should increase the proposed
setbacks to 3,500 feet and should not treat private wells and public
groundwater wells differently.
e. Setbacks of 300 feet from trails or 600 feet from “irreplaceable natural
areas” and “wildlands," 1,000 feet from drinking water wells and 2,000
feet from public groundwater wells, surface water intakes and reservoirs
all seem inadequate. Setbacks should be increased to 3,000 feet to 4,000
feet.
f. A setback of 3500 feet should be required to keep drill pads and support
facilities such as roads, pipelines and compressors away from water wells
(both public and private), schools, homes and office buildings. This is
essential to protect clean drinking water and public health and safety.
g. All drinking water setbacks in the Best Management Practices report
should be increased to 3,300 feet.
h. In Garrett County alone, approximately 14,394 households rely on
groundwater wells for their drinking water supply. Given the wider radius
of contamination of shallow groundwater resources demonstrated by the
most current science, I recommend setbacks for residential and public
water supplies no less than 1 kilometer (3,280 ft.)
i. Setbacks for well pads and infrastructure from private and public water
wells, rivers, creeks, homes, schools, and office buildings should be at
least 4,500 feet.
j. Setbacks for well pads and infrastructure from private and public water
wells, homes, schools, and office buildings should be at least 1 mile.
k. Setbacks from all occupied buildings and recreational facilities should be
at least 2,000 feet.
l. The logic evades me; commission the UMCES-AL study, pay for it, then
disregard the findings. The setback distances, almost unilaterally have
been halved when they should have been doubled or tripled according to
the latest research findings.
Ideally, the groundwater flow conditions would be specifically known at every
location; in practice, however, this is not possible. Knowing the direction of
groundwater flow would enable the Departments to establish a setback to protect
users whose wells lie in the direction of the groundwater flow; a lesser setback or no
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setback might be appropriate to protect users whose wells lie in the opposite
direction. In practice, and for the purpose of establishing setbacks of general
applicability, regulators settle on a less scientific radial setback; that is, a distance in
all directions, not just in the flow direction.
A recent article, A geochemical context for stray gas investigations in the northern
Appalachian Basin: Implications of analyses of natural gases from Neogene-through
Devonian-age strata, Baldassare et al., AAPG Bulletin, (February 2014), stated in the
Summary and Conclusions section:
Reports of alleged stray gas migration can be the result of preexisting,
and previously undiagnosed, methane in the shallow aquifer system, or
the result of gas well operations, or other anthropogenic activity. Gas
concentration variability in a water well over time can be the result of
changes in hydrostatic head induced by pumping or by seasonal
fluctuations in the water table. Alleged incidents of stray gas
migration require investigations at the site specific level and
evaluation and synthesis of multiple data types to determine the source
of the stray gas. Site-specific investigations should include definition
of gas and groundwater geochemistry and mechanism of migration.
Comprehensive predrill groundwater quality sampling is often
essential to distinguish preexisting natural gas in the aquifer systems
from gas-well activity-induced stray gas migration. Alleged stray gas
migration incidents must be monitored and sampled sufficiently
following specific methodologies and investigation protocols to
determine if the alleged incident is a natural condition or the result of
natural gas-well activity.
The Departments are aware of the peer-reviewed scientific journal articles which
report water quality data and assess whether there is a correlation between the
concentrations of methane and dissolved metals in well water and distance from gas
wells. Some of the articles show a statistical correlation and some do not. For
example, Dr. Avner Vengosh, in his presentation at the April 14, 2014, meeting of the
Advisory Commission, noted that he found no correlation between methane levels and
proximity to gas wells in Arkansas, but that he did find increased stray gas
abundance in drinking water wells within a kilometer of active gas wells in a part of
northeastern Pennsylvania. Based on isotopic fingerprinting and other factors, he
concluded that water wells near gas wells in northeastern Pennsylvania contained
Marcellus production gases or a mixture of Marcellus gases and other gases. He
wrote: “In cases where the composition of stray gas is consistent with the target shale
formation, it is likely that the occurrence of fugitive gas in shallow aquifers is caused
by leaky, failing, or improperly installed casings in the natural gas wells. In other
cases, hydrocarbon and noble gas data also indicated that fugitive gas from
intermediate formations apparently flowed up through the outside of the well annulus
and then leaked into the overlying shallow aquifers.” Vengosh et al., A Critical
Review of the Risks to Water Resources from Unconventional Shale Gas
Development and Hydraulic Fracturing in the United States, Environmental Science
and Technology (2014).
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It is known that methane can appear in drinking water wells in western Maryland
without any relationship to gas wells. The Maryland Geological Survey (MGS)
recently performed a pilot study to determine background (before horizontal drilling
and hydraulic fracturing) methane levels in drinking water wells in Garrett and
Allegany Counties. The results are consistent with other reported data that shows a
relationship between topography and methane content. MGS categorized wells as 1)
in valleys in coal basins; 2) on hilltops or hillsides in coal basins; 3) in valleys but
not in coal basins; and 4) on hilltops or hillsides but not in coal basins. The authors
report:
With respect to the four well-location categories targeted in this study, … valley
wells in coal basins had the highest proportion of detections (11 of 15 wells, or
73 percent), followed by coal/hilltop+hillside (9 of 20 wells, or 45 percent),
non-coal/valley wells (7 of 17 wells, or 41 percent), and noncoal/hilltop+hillside wells (7 of 25 wells, or 28 percent).
The authors also sampled a small number of wells approximately monthly, and found
that “The average percent difference from the median monthly methane
concentration in each well was between 20 and 30 percent, although individual
variations in each well were frequently larger.”
The Vengosh data present a convincing case for contamination of shallow drinking
water aquifers by stray gas within 1 km of active Marcellus wells in certain areas of
northeastern Pennsylvania. Data from Arkansas indicate that methane concentration
in shallow drinking water aquifers does not show an increase with proximity to
natural gas wells. During the Advisory Commission’s April 14, 2014, meeting Dr.
Vengosh said he does not know why methane is higher in drinking water wells near
gas wells in Pennsylvania, but not in Arkansas. The wells were operated by different
companies. In Pennsylvania air drilling has been used instead of drilling with mud
because it is faster; he speculated that mud drilling may result in better casing and
cement. There are geological differences, but there is no strong evidence to say
whether the difference lies in better practices or different geology.
If practices lessen the chance of methane release, a combination of practices and
setbacks could work together to protect shallow drinking water aquifers. The
Departments are proposing specific well casing, cementing, testing and repair best
management practices to minimize the rate of well failure and the associated
potential for methane migration. These, combined with a significant setback and
monitoring requirements, are appropriately protective of drinking water wells.
In its 2011 draft Supplemental Generic Environmental Impact Statement on hydraulic
fracturing, the New York State Department of Environmental Conservation
recommended “that regulations be adopted to prohibit high-volume hydraulic
fracturing in both the NYC and Skaneateles Lake watersheds, as well as in a 4,000 foot buffer area surrounding these watersheds, to provide an adequate margin of
safety from the full range of operations related to high-volume hydraulic fracturing
that extend away from the well pad.” These two drinking water systems draw from
surface water. Such systems are generally required by regulations promulgated
under the federal Safe Drinking Water Act, known as the Surface Water Treatment
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Rule, to filter the water before delivering it to users. There are two major surface
drinking water sources and systems located within New York that have been granted
permission by EPA and NY State Department of Health to operate as unfiltered
drinking water supplies. These are the New York City and City of Syracuse water
supplies and associated watersheds.
Heightened public health concerns are associated with unfiltered surface water
systems because the only treatment that these drinking waters receive is basic
disinfection through methods such as chlorine addition or ultraviolet light
irradiation. There is no use of widely employed treatment measures such as chemical
coagulation/flocculation or physical filtration to remove pathogens, sediments,
organic matter or other contaminants from the drinking water. Protection of the
watershed is the only defense. New York has invested billions of dollars in protecting
these watersheds, in part to avoid the additional billions of dollars it would cost to
construct a treatment plant and the hundreds of millions a year it would cost to
operate the plant.
There are no unfiltered surface drinking water supply watersheds in Garrett or
Allegany Counties. If there were, it would be appropriate to consider them for
additional protection.
This issue will be closely monitored by the State. The Departments will continue
reviewing new research and reports on the relationship between hydraulic fracturing
and the concentration of methane and dissolved metals in drinking water wells.
These concerns underscore the critical importance of the approach proposed by the
State to require comprehensive ground and surface water monitoring in wells and
streams, before, during and after hydraulic fracturing events. Regulations are not
static and can be changed as new information becomes available.
The Departments accepted almost all of the setbacks recommended by the UMCESAL report. The exceptions were limestone outcroppings and coal mines, and reasons
were given for the suggested changes. The Departments note here that the initial
changes to limestone outcrop setbacks have been revised based on a reassessment of
limestone outcrop dip angles in Garrett and Allegany Counties. The 500 foot setback
from the downdip side of limestone outcrops has been expanded to 750 feet to provide
greater assurances that caves will not be encountered while drilling. The
Departments recommended larger setbacks than the UMCES-AL report
recommended in some instances.
6. The setbacks are insufficient to protect public safety.
a. Fracking infrastructure, like compressor stations and pipelines, has caused
explosions and fires in communities in PA, NJ, CA, OK, and more. Your
current setbacks of as little as 300 feet are not sufficient to protect
Marylanders from these risks.
b. Recommend including a 2 mile “disaster mitigation” set back from
existing incorporated town limits to emphasize human population safety.
See data on recent natural gas compressor station explosions and
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evacuation actions by local public safety authorities- usually a 2 mile
radius.
c. There should be a setback from existing communities and concentrated
population centers.
d. The use of open space/agricultural sites or TRULY ZONED industrial
sites for compressor stations should be chosen preferentially over sites
within 2 miles of established population centers.
e. The potential for ground water contamination from spills or other
conditions where chemicals from fracking mixtures may be involved
indicate that the Departments need to review their setback requirements
and equally important need to develop baseline data on various chemical
parameters as well as methane in water wells and aquifers in Western
Maryland.
There have been fires and explosions related to the gas infrastructure. The
recommended setback for compressor stations is 1,000 feet from any occupied
building. Under federal regulations, all transmission lines are subject to design,
installation, construction, and testing and inspection requirements and even
intrastate gathering lines are subject to design, installation, construction, and initial
testing and inspection requirements if there are more than 10 buildings intended for
human occupancy within 220 yards on either side of the center line for any
continuous one mile segment of pipeline. These setbacks and standards significantly
reduce the risk to public safety.
As noted above, Section 14-108 of the Environment Article of the Maryland Code
deals with individual permit applications and requires MDE to deny a well permit if it
determines that proposed drilling or well operation poses a substantial threat to
public safety or a risk of significant adverse environmental impact to, among other
things, populated areas or if the proposed operation will constitute a significant
physical hazard to a neighboring dwelling unit, school, church, hospital, commercial
or industrial building, public road, or other public or private property in existence at
the time of the application for the permit; or if the operation will have a significant
adverse effect on the uses of a publicly owned park, forest, or recreation area in
existence at the time of the application for the permit. Section 14-108 requires
consideration of the individual permit application, and will be used as appropriate to
protect these areas from substantial threats to public safety.
Existing communities and population centers are protected by setbacks and other best
practices. An evacuation zone is not comparable to a setback and is often established
conservatively when an incident occurs. The Comprehensive Gas Development Plan
is one mechanism for directing the location of pads and infrastructure towards areas
more appropriate for industrial activities and away from population centers and
sensitive natural resource and agricultural areas.
The risk of contamination of groundwater from spills of chemicals and mixtures is
addressed through the stormwater requirements and the Spill Prevention, Control
and Countermeasures and Emergency Response provisions. The Departments intend
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to require baseline monitoring data on relevant chemicals and require periodic
monitoring after operations begin.
7. There should be setbacks for infrastructure.
a. The State should provide oversight on placement of MSGD infrastructure.
b. Considerations of setback requirements should be expanded to include the
gas delivery system (gathering lines, etc).
c. The draft BMPs recommend a 1,000 ft. setback between a compressor
station and an occupied structure. At the very least this restriction should
also apply to distance of compressor from cultural assets, waterways and
roadways.
d. I am also appalled that the state has no control over the siting of
compressor stations and gathering lines.
e. Compressor station setbacks should be from property lines. As drafted,
the BMPs provide a 0’ setback from property lines. This creates a safety
issue for the adjoining property owner who does not have the benefit of an
“occupied building” on their land or near their property line, precluding
the peaceful and safe use of their property, as well as limiting future
improvement and development of their property.
f. Provide a BMP setback for pipes, tanks, valves, and related infrastructure
after drilling. This infrastructure presents significant safety, health and
environmental hazards should failure or accidents occur. To the extent that
these regulatory issues are not in the purview of the MDE or DNR, the
Commission should issue a strong statement calling for these to be
developed in Maryland, by the appropriate entity, and that no drilling
should occur until such time as these protections are put in place
g. Are there no setbacks proposed for “infrastructure improvements” such as
access roads and pipelines? Road and pipeline construction could impact
critical and sensitive areas.
The State plans to oversee placement of MSGD infrastructure by setbacks and by the
CGDP. The draft report recommended expanding drill pad location restrictions and
setbacks listed in Table 1-2 to all gas development activities that will result in
permanent surface alteration that would negatively impact natural, cultural and
historic resources. This includes permanent roads, compressor stations, separator
facilities and other infrastructure needs. This expansion applies to aquatic habitat,
special conservation areas, cultural and historical sites, State and federal parks and
forests, trails, wildlife management areas, wild and scenic rivers and scenic byways.
The location of gathering lines will also be addressed in the CGDP.
The United States Department of Transportation, Pipeline and Hazardous Materials
Administration has established siting restrictions on compressor stations. The
regulation, 49 CRF § 192.163(a) provides:
Location of compressor building. Except for a compressor building on
a platform located offshore or in inland navigable waters, each main
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compressor building of a compressor station must be located on
property under the control of the operator. It must be far enough away
from adjacent property, not under control of the operator, to minimize
the possibility of fire being communicated to the compressor building
from structures on adjacent property. There must be enough open
space around the main compressor building to allow the free
movement of fire-fighting equipment.
8. Comments on waivers of setback requirements.
a. If setbacks are minimally protective distances, they should never be
waived. Parents should not be allowed to consent to waivers on behalf of
their children.
b. There should be no waivers, and current setbacks are not sufficient.
c. Further, while we recognize Garrett County does not currently have
county-wide zoning, the study recommends exceptions “for good cause
shown and with the consent of the landowner protected by the setback,
MDE may approve exceptions to the setback requirements.” Setback
provisions, and exceptions, should be developed for contiguous and
adjacent properties to protect those landowners.
d. The open-ended set-back waiver leaves open the exact door that so many
states, specifically West Virginia with only 200 feet, that has been left
open where large, industrial HVHF well pads and processes are within a
stone’s throw of family’s homes, churches, schools and public areas. Setbacks should be black & white to keep industrial zoning separate from
residential and community zoning regardless of what one party thinks it
appropriate.
e. Allowing individual landowners to waive setback requirements infringes
on rights of all other nearby residents to expect full protections from the
State’s regulations and from the CGDP process. The provision for
exceptions can easily be abused by industry, effectively negating
protections put in place in this section. It also opens the possibility of
aquifer contamination to occur in a shared water source that might
otherwise have been afforded protections if original setback guidance was
observed. Setback waivers should only be permitted with the approval of
all surrounding landowners who would have been afforded more complete
protection if the original setback remained in force.
f. No waivers should be allowed to the 1000 feet rule for water wells on
private property unless the surface owner is also the mineral rights owner.
g. The recommendation should provide a provision that the owner(s) of
leased property, the lessor, can allow the well to be located closer than
1000 feet to his own water supply.
The Departments propose to consider requests for exceptions to a setback
requirement “for good cause shown and with the consent of the landowner protected
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by the setback.” An existing example of a setback requirement and a waiver
provision can be found in § 14-112 of the Environment Article, Maryland Code:
(a) Distance from property boundary. -(1) Except as provided in paragraph (2) of this subsection, a well for
the production or underground storage of gas or oil may not be drilled
on any property nearer than 1,000 feet to the boundary of the property
except by agreement with the owners of the gas and oil on adjacent
lands.
(2) A well for the production of coalbed methane may not be drilled
on any property nearer than 500 feet to the boundary of the property
except by agreement with the owners of coalbed methane on adjacent
lands.
(b) When well may be located close to property boundary. -- On
property on which it is impossible to locate a well the required
minimum distance from the boundary, and where no agreement with
the owners of the gas and oil or coalbed methane on adjacent lands
has been made, a well may be located nearer than the required
minimum distance under subsection (a) of this section to the boundary
with the consent of the Department. However, when any permit to drill
a well nearer than the required minimum distance to the boundary has
been applied for, the Department shall notify every landowner, royalty
owner, or leaseholder within the required minimum distance of the
location of the proposed well, giving them a reasonable opportunity to
file objections to the issuance of the permit. The Department then shall
hold a hearing. If the Department determines that it is necessary for
the well to be located nearer than the required minimum distance to
the boundary, it may issue the permit. If a permit is issued, any
landowner, royalty owner, or leaseholder within the required
minimum distance of the proposed well has the right to a rehearing
and appeal to the courts provided in this subtitle. A request for a
rehearing or an appeal to the courts stays the authority granted under
the permit until final determination of the issued permit is made.
Another example can be found in COMAR 26.19.01.09G:
The Department may not issue a drilling and operating permit if the
well location is closer than 1,000 feet to a school, church, drinking
water supply, wellhead protection area, or an occupied dwelling
unless written permission of the owners is submitted with the
application and approved by the Department.
In general, people are free to voluntarily relinquish a right, such as the right not to
have a well drilled closer than 1,000 feet to an occupied dwelling. If the Department
of the Environment determined that the proposed operation with the waiver would
pose a substantial threat to public safety, it could not grant the permit with the
waiver.
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Whether a parent can waive a child’s rights is a question that arises in many
contexts. It is a matter of state law.
9. General setbacks are not appropriate; local conditions should be considered.
a. It is problematic to apply standard setback requirements to local
geological conditions; site-specific formations must be considered.
b. Setback requirements for the several categories appear to be somewhat
arbitrary and not based in topographic realities. Each proposed setback
should be reviewed and analyzed against protections for environment;
public health, welfare and safety; defense of Garrett County’s tourism and
outdoor / adventure industries; and for protection of property values of
contiguous and nearby properties to Marcellus gas operations.
c. Natural fractures of the bedrock beneath central and western Maryland
contain potential drinking water resources, and shale gas boreholes should
be set back from these geological features. These fractures complicate the
casing and cementing of wells that pass through them, increasing the risk
of subsurface leaks.
d. The 1320 foot setback from historic gas wells (from both the vertical and
horizontal well bore) is being recommended with no real technical basis. It
may be reasonable to recommend “identification” of existing wells within
a certain, somewhat arbitrary, distance as part of the permitting process to
ensure those wells are appropriately recognized and considered, but it’s an
entirely different issue to establish that as a mandatory setback. Setbacks
should be established to balance environmental protection and
development. Overly restrictive setbacks can have the unintended
consequence of essentially reducing the area available for drilling.
e. The setback requirements should not be arbitrarily picked and there should
be some criteria and a scientific basis rather than a "farther is better"
approach.
f. If the State mandates a 2,000 setback from existing and historic gas
extraction activities, it is unclear how the State can also permit much
larger, deeper and more complex wells to be drilled in close proximity to
other wells on a CGDP well pad.
g. In addition to historic gas wells, there should be consideration to setbacks
or conditions placed on fracking near existing production wells. Fracking
near existing wells can result in a “frack hit” on an active production well
that could result in a blowout of the well equipment on the production
well. This problem can be avoided either by setbacks or by special
preparation of the production well to handle a possible “frack hit”.
Setbacks are general rules that are appropriate in most cases. Site specific
information will be considered, however, in both the CGDP and the application for
the individual permit. Any oil or gas well drilled from the surface will pass through
freshwater aquifers. The best practices requiring pilot holes, setbacks from limestone
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outcroppings, and those relating to casing and cement provide a measure of
protection from subsurface contamination.
Current regulation COMAR 26.19.01.09E currently provides:
The Department may not issue a permit to drill and complete a gas
well closer than 2,000 feet to an existing gas well in the same reservoir
unless the Department is provided with credible geologic evidence of
reservoir separation to warrant granting a spacing exception.
This regulation was written before the widespread use of horizontal drilling and
multi-well pads. This regulation will have to be amended or an additional regulation
specific to multi-well pads will have to be developed. The Departments will consider
the existence of existing gas wells when reviewing permit applications. The draft
report recommended that all portions of the borehole, including laterals, should be at
least 1320 feet from historic gas wells.
10. Clarification is needed.
a. Depending on how the terms “stream” and “seep” are defined, these
aquatic habitats may not be adequately mapped.
b. It would be helpful to have a definition of “for good cause shown” in
connection with waivers of setbacks.
c. There are a number of proposed setbacks within the document, many of
which are in conflict with each other. For example, it is unclear on page 30
with respect to the drilling of a pilot hole within 500 feet of the proposed
borehole, whether the setbacks for the pilot hole would be the same as for
the final developed well. There are no provisions for using the same pilot
hole for the main borehole of the well if no issues are identified during its
drilling.
d. Another example of significant uncertainty in the document is with the
300 feet setback from various “recreational use areas” clearly
recommended on page 16, versus the suggestion on page 18 that it may be
doubled to 600 feet based on a workshop anticipated later this year.
e. In Table I-2, the “to” section describes from the “edge of the drill pad
disturbance” and should include a descriptive outline that includes the
sedimentation and erosion controls and storm water controls as the limits
of disturbance (LOD) for the setbacks.
f. Setback from Compressor station – The table does not make it clear
whether the setback from an occupied buildings for compressor stations is
from the actual building housing the compressor, or from the building and
associated infrastructure, or from the limits of the property that houses the
compressor station. This should be clarified.
g. Avoiding times of peak outdoor recreational periods is meaningless if an
exception is allowed based on the assertion that once fracturing operations
have begun, it is generally not safe to halt activities. This exception will
diminish the State’s ability to restrict the timing of fracturing activities.
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The driller is essentially enabled to ignore peak recreational periods and
wildlife needs, conduct the hydraulic fracturing phase at will, and claim
that it is unsafe to halt activities because they have already begun.
h. The provision recommending that drilling should avoid times of peak
outdoor recreational periods is unreasonably restrictive. What purpose is
served by restricting drilling on first day of trout season verses any other
day of trout fishing? Not likely that the trout will quit biting in the
Potomac River if a gas well drilling operation starts near Keyser's Ridge.
i. The setback for occupied buildings should be 1,000 feet from the well site
and compressor equipment (if located off-site) instead of the proposed
borehole. Should a structure holding livestock be defined as “occupied?”
Noise, vibrations, odors and light will impact adjacent buildings. In
addition, setback consideration should be made for unoccupied
agricultural buildings (such as hay storage).
j. The recommendation on conservation banking for forests [a Siting Best
Practice] does not make clear how conservation banking will be used.
Does this mean that the drilling company can undertake or contribute to
conservation efforts elsewhere if impacts in western Maryland cannot be
avoided? Will the Agencies consider credit trading to satisfy forest
conservation mitigation for western Maryland forests? Will a local
stakeholder be a part of decision-making regarding the use of conservation
banking?
k. Setbacks from floodplains should increase and be based on a minimum
distance and elevation, whichever is greater.
l. Why is there a setback for wildlife but not for livestock?
m. All BMPs of setbacks from “occupied building” should be changed to
property line. Rural areas are sparsely populated and have more land
parcels than occupied buildings. Setbacks are more appropriately set from
property boundaries to afford equal protection to all landowners,
regardless of the extent of the current development and use of their
property. Setbacks from property lines are the standard approach in almost
all land use regulations.
n. The BMPs provide minimum setbacks for public drinking water protection
- only public groundwater wells or surface water intakes have setbacks.
Public drinking water source areas outside of the intake or well setback
zone receive only the 300’ aquatic habitat setback.
o. The towns of Friendsville and Oakland use the Youghiogheny River as a
public drinking water source. Setback protections from the main stem of
the Youghiogheny River upstream from Friendsville and Oakland should
be the most stringent – 2000’ as a drinking water source and not the 300’
aquatic habitat standard.
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p. Our county, state and federal lands and resources cannot be used to drill
by the fracking/gas companies, in order to preserve nature, protect our
wildlife, and the water that flows through it.
q. Fracking and or drilling cannot take place within 200 yards of any private
well or public water sanitation areas.
r. Fracking underground of personal property without their express written
permission of the landowner, would not be permitted. In addition, that
landowner would also receive a royalty fee from the company and eligible
to make claims against the shale fracking/drilling companies, if warranted.
s. For aquatic habitat (riparian), the UMCES-AL Report cited recommended
varying setbacks based on biodiversity. The lowest setback was 330 feet
and the greatest was 1,240 feet (Table 5-2 and page 6-4). Why are the
Departments recommending a setback of 300 feet? Does the setback
provide adequate protection? Usually riparian areas are protected by
vegetated buffers. Will these buffer areas be factored into the setback
calculation?
t. For drinking water wells and surface water intakes, the UMCES-AL report
recommends “extended” setbacks from on-site storage areas, hazardous
materials and collection tanks for produced water. Should additional
setbacks be proposed?
u. Since setbacks offer the primary protection, it is extremely important that
they are correctly identified, including whether they are measured from
the borehole or the edge of the pad.
v. The report recommends expanding drill pad location restrictions and
setbacks listed in Table 1-1 to all gas Development activities resulting in
permanent surface alteration that would negatively impact natural, cultural
and historic resources. This would severely restrictive for roads and
infrastructure. This provision could make it impossible to put in gas
pipelines through or along county roads in state parks and lands and
perhaps even difficult to construct a road from public right of way to a
well site. This provision conflicts with the intent of the report to limit
development impacts and forest bifurcation.
w. Expanding the setbacks from public outdoor recreational use areas would
give the State control over massive amounts of private property and
restrict landowner's ability to lease or have natural gas development on
their property that borders on state land if these setbacks include all
aspects of natural gas development.
x. Section IV.B.2 suggests that forest loss could be evaluated differently
depending on whether the loss is temporary or permanent. How could a
forest loss be temporary?
Not all “streams” and “seeps” may be mapped, but the applicant for a CGDP will be
required to do a rapid field assessment for unmapped streams, wetlands and other
sensitive areas.
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“For good cause shown” is a general phrase meaning that a reasonable basis must
be demonstrated. It appears multiple times in Maryland statutes and regulations.
Where two different setbacks apply, the applicant would have to comply with the
more stringent setback. A pilot hole that is not a gas well and does not become a gas
well would not be subject to the setback regulations for gas wells. Provided the pilot
hole meets the requirements for a gas well, the company could make application for a
gas well permit and use the pilot hole for the borehole.
It should be assumed that the Departments will propose to adopt the recommended
setbacks. Understand, however, that regulations can be changed, and more stringent
provisions can be incorporated into individual permits.
The words “edge of the drill pad disturbance” will be clarified. It was meant to refer
to the limit of disturbance as indicated in the grading plan for the drill pad.
The 1,000 foot setback for compressor stations will be measured from the building or
buildings that contain the compressor station operations. As noted above, there are
federal regulations that impose siting restrictions on compressor stations.
Although fracking is generally carried out without pause, the date on which the
fracking begins can be largely controlled. The times of peak outdoor recreation can
be anticipated. Garrett County sees heavy tourist travel to parks on routes, such as
State Park and Rock Lodge Roads around Deep Creek Lake NRMA and Deep Creek
Lake State Park. The initiation of drilling and fracking, along with the accompanying
truck traffic, could be timed to reduce safety hazards to hikers, bikers, boaters, and
park patron traffic during the summer months. Similar logic applies to the first day
of trout season. This kick-off day attracts many anglers to the roadways and streams
in western Maryland. The State would like to minimize the public safety hazards on
this high traffic day. Of course, the proximity of the recreational activity to the
hydraulic fracturing site would also be considered.
The Departments agree that the 1,000 setback for occupied buildings should be
measured from the edge of the well pad, not the borehole. A structure occupied by
livestock would not be considered “occupied.” These and unoccupied farm buildings
should be adequately addressed by other setbacks and best practices.
The Departments prefer that forest mitigation through conservation banking or
another mechanism occurs within the affected county of impact, and ideally within
the affected watershed. However, the State realizes that reforestation opportunities
may be limited and that the mitigation actions may need to occur outside of western
Maryland. The State will encourage stakeholder review as these mitigation options
are developed. Setbacks from floodplains, like other setbacks, can be adjusted in
permits. The draft report recommended that well pads shall not be constructed on
land with a slope > 15 percent. It also stated that setback distances may be expanded
on a case by case basis if the area includes steep slopes or highly erodible soils.
There are setbacks for wildlife management areas, not for wildlife per se.
There are reasons for establishing some setbacks from the property line and others
from occupied buildings. For example, existing law, which the Departments do not
recommend changing, requires that a well be at least 1,000 feet from the boundary of
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the property on which the well is to be drilled (unless MDE grants a waiver). Section
14-112 of the Environment Article of the Environment Code and COMAR
26.19.01.09C and D. This would mean that the well cannot be closer than 1,000 feet
from another person’s property line, whether the other person’s property has been
improved or is raw land. Another existing regulation requires that a well be at least
1,000 feet from a church or occupied dwelling unless the property owners consent in
writing. COMAR 26.19.01.09G. This provision would protect an occupied dwelling
on the property on which the well will be drilled.
The Departments are proposing more protective setbacks for sources of drinking
water. See the response to comment 4, above.
The draft report recommended that all cultural and historical sites, state and federal
parks, trails, wildlife management areas, scenic and wild rivers, and scenic byways
be off limits to surface disturbance and be further protected by a setback of 300 feet.
The Department of Natural Resources’ written policy states, “Use of water resources
or water rights from lands owned and managed by DNR may only be granted for
documented remediation of severe human health or safety needs.”
With regard to the reference to “public water sanitation areas,” the Departments
assume the reference is to wellhead protection areas. The Departments are
proposing a 1,000 foot setback from such areas.
Wells cannot be drilled or fracked on or under land unless the owner of the mineral
rights consents. In the event that the surface rights and mineral rights are held by
different persons, the surface owner must make reasonable accommodations to the
holder of the mineral rights to allow the extraction of gas or other minerals from
under the surface owner’s land. Greater clarity and more protection could be
established by a Surface Owner’s Protection Act (SOPA), which has been enacted in
some jurisdictions. The Advisory Commission was not able to agree on
comprehensive provisions of a SOPA.
The UMCES-AL report cited research regarding appropriate setbacks for different
species in aquatic habitat, but recommended a 300 foot setback. The Departments
initially accepted the recommendation, but, upon further review of scientific
literature, expanded the aquatic habitat setback to 450 feet for biodiversity and water
quality protection. Setbacks are measured from edge of the targeted habitat and
define the buffer width. While trees are generally considered the most protective
vegetation type for habitat and water quality, the buffer may include other types of
vegetation.
The Departments are recommending that secondary containment be mandatory for
chemical storage areas and tanks. For this reason, no additional setbacks are
proposed.
The Departments will be specific as to whether setbacks should be measured from the
borehole or the edge of the pad.
The setbacks for permanent surface alteration that would negatively impact natural,
cultural and historic resources will not restrict such alterations unless there were a
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permanent negative impact. It is anticipated that a very small percentage of such
alterations would have such an impact.
The setbacks from public outdoor recreational use areas are restrictions on surface
disturbance. With horizontal drilling, these areas will not be off-limits to gas
development.
Temporary forest loss occurs when an area has been cleared for a temporary use, but
will then be allowed to re-grow back to a forest. The reforestation may occur
naturally over time or through planting activities. This situation could occur if forest
is cleared for a drill pad and then the area of the pad is reduced, allowing a certain
portion of the cleared area to be reforested. If the loss is permanent, this would be
used to justify higher reforestation or conservation mitigation ratios. For example,
for one acre of permanent forest loss, two acres may be required to offset the impact.
Mitigation ratios for temporary losses may not be as high.
11. The setback should consider the horizontal wellbore and not only the vertical
wellbore or the edge of the pad.
a. A setback of 1,000 feet is inadequate on its own terms and close to
meaningless if horizontal drilling extends the exploitation zone thousands
of feet in every direction from the well pad.
b. The setback distances in general sound okay, but when dealing with
drinking water reservoirs, such as the Frostburg Reservoir and others in
Garrett County, the distances should be greater than those recommended
by Eshleman and Elmore. If horizontal boreholes can extend 7000 feet, I
think that the setback distance from key drinking water resources should
be at least 7000 feet.
c. The setbacks should consider not only contamination from events at the
land surface, but also those that occur beneath.
d. The currently specified setback from any drinking water well presumes
that contamination comes from pollution events that occur at or near the
land surface (on the pad, in collection ponds, whatever). Events that are
inevitably occurring beneath the land surface are ignored. Ignorance is no
excuse when protection of natural resources and the health of citizens are
involved.
e. The “Location restrictions” discussion ignores the effects on wetlands,
fresh water aquifers, etc., of the upward migration of induced zones of
enhanced vertical permeability. Unfortunately, criteria for “setbacks” are
applied only to the pad and to other activities and events taking place at
the land surface. These applications are necessary, but are not sufficient.
Though one can expect historic gas wells (and environs) to mark locations
where vertical upward flow of gas and pollutants may occur, they do not
mark the only locations where one can expect to find sooner or later zones
of enhanced vertical permeability that eventually will reach the land
surface and hence will introduce future upward flow of methane gas not
only to fresh water aquifers and wetlands, but also to the atmosphere. One
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should also consider the effect that formation-to-formation geologic
heterogeneities have on the mapping of where zones of enhanced
permeability may be expected to migrate. Ditto for the locations and
geometries of deep coal mines.
f. If the horizontal part of the well could be drilled as far as 8,000 feet,
property lines are not protected if the setback is 1,000 feet!
The risk of contamination of surface water and drinking water aquifers arises mainly
from activity at the surface or from deficiencies in the casing and cementing of the
vertical borehole. The hydraulic fracturing occurring at depths 2,000 or more feet
below the lowest drinking water aquifer poses little threat. The issue of upward
migration is addressed in the responses to other comments.
12. The recommended setback from coal mines are appropriate. UMCES-AL
recommendations with regard to setbacks from mapped underground coal mines
to the borehole are unnecessarily restrictive, as appropriately noted by the
Departments in the August, 2013 Draft Marcellus Shale Safe Drilling Initiative
Study Part II. The Board of Directors and committee members of the Casselman
Coal Poolee Association endorse the Departments recommendations with regard
to this critical issue. Pre-drill planning including careful site evaluation and pilot
hole investigations is the safest and most effective method to identify these
features. As noted by MDE’s mining program, Maryland’s deep coal mines cover
thousands of acres, but are only several hundred feet deep, and can be safely
cased through, utilizing pilot holes to precisely identify and locate any voids. The
MDE and DNR have appropriately proposed that the best practice is to conduct
pre-drill planning in any area where underground mining is suspected within 500
feet of the prospective borehole, based on a review of available records. The
Departments have recommended that the pre-drill planning shall include selection
of drill hole locations that avoid all mine voids and assures lateral support of drill
holes during drilling and casings during well construction. If such locations
cannot be found, voids must be filled or isolated with multiple concentric strings
of casing and cement. We fully endorse these recommendations.
The Departments agree.
TRUCK TRAFFIC
1. Consideration should be given to truck traffic adjacent to schools. The amount of
dust and particle emissions from the diesel engines would impact the health of
school children, especially those on playgrounds. It is common practice for truck
owners to modify their diesel injection systems to generate more power.
However, the result of these modifications is a large increase in black soot from
the trucks' tailpipes. This will need to be regulated if the trucks are to go past a
school.
The review of roads and travel routes would be a consideration in the Comprehensive
Plan initially when the planning phase of development would occur. Truck routes
and times would be discussed more thoroughly in the context of individual permit.
County and State roads agencies as well as other local agencies will need to be a part
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of this discussion and in most cases will take the lead in this effort. Any commercial
vehicle needs to meet the requirements of current transportation law and will be
subject to penalties for non compliance. Steps will be taken to ensure inspection of
trucks.
2. The report's recommendations fail to recognize that most of the truck traffic
generated from Marcellus Shale drilling is short-term, typically occurring over a
few months during site preparation of the well (e.g., hauling pipe, water, etc.).
Once a well is established, truck traffic significantly decreases as gas is
transported via pipeline.
This is a valid point, but truck traffic can be very heavy over the short term, and the
“short term” can last for a long time if multiple wells are drilled. In addition, the
Departments must consider cumulative impact.
3. Do we demand the companies profiting from MSGD be financially responsible
for the effect of the increased heavy vehicle traffic on our roads, or go the way of
Texas and just let our roads revert to gravel?
Oversize or overweight vehicles must obtain special permits to travel on State roads,
and the permittee is responsible for payment of all damage that the vehicle causes,
either directly or indirectly, to any road surface, bridge, or other structure, whether
maintained by the State Highway Administration or by another entity. Trucks pay
State roadway taxes and fees that are meant to provide for the upkeep of state roads
from normal (not overweight or oversize) vehicles.
Counties also have weight restrictions on some roads. Experience has shown,
however, that even vehicles that are within weight and size restrictions can cause
damage to local roads if, for example, the truck trips are frequent or occur during
freeze and thaw periods. The draft best practices report included a requirement that
the applicant must “enter into agreements with the county and/or municipality to
maintain the roads which it makes use of, in the same or better condition the
roadways had prior to the commencement of the applicant’s operations, and to
maintain the roadways in a good state of repair during the applicant’s operations.”
This can be accomplished through a Road Use Agreement between the applicant and
the County or municipality. Such agreements are common, and the Departments
expect they will be used for this purpose.
4. Not only will the road and bridge infrastructure be damaged, but we also foresee
very significant safety issues particularly where the large trucks and concentration
of activity on small county and park roads will undoubtedly lead to a significant
increase in accidents. Traffic patterns and road usage would have to be closely
monitored or prohibited in some cases.
See response to comment #1.
5. Please change “should” to “shall” in “Trucking should be closely monitored
during high-use and wet periods if it is not possible to suspend activities.”
Monitoring will be done when necessary.
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6. It may be politically difficult for local officials to enforce agreements with
companies to fix roads or pay for them. It might be better for the State to take on
this responsibility.
The State is willing to work with the Counties to ensure that roads are maintained,
but the primary responsibility for maintenance and repair of the roads is with the
county or state roads agency responsible for that particular road. See response to
comment #3.
7. There are several comments on timing of heavy trucking. The highlighted times
listed on page 26 are an extension of API recommendations that a transportation
plan be incorporated into the overall project plan and that the plan address traffic
needs. A more complete review of the recommendations contained in the API
recommended practices associated with transportation planning could assist the
state in this area.
An API standard relating to transportation planning would qualify as a “relevant API
standard.” The best practice report requires that the applicant for a well permit file
a plan that follows the normative elements of relevant API standards, or demonstrate
that an alternative is at least as protective.
8. Many of the recommendations included are unrealistic. For example, encouraging
"maximum movement of heavy equipment by rail to protect road systems and
prevent accidents" is idealistic. While rail is a viable long-haul transportation
option, the last miles traveled in the geographic region will ultimately be made on
a truck. The requirement that "all trucks, tankers and dump trucks transporting
liquid or solid wastes be fitted with GPS tracking systems" is virtually impossible
in an industry that is deregulated, highly fragmented, and uses a large number of
independent contractors to meet short-term transportation needs.
The Departments realize that there will inevitably be truck traffic to individual well
sites. The purpose of the statement was to recommend consideration of other means
of transportation where available. The use of GPS in tracking is becoming more
common, and the permittee can require the use of such equipment by trucks serving
the permittee’s operations.
9. “Encourage local jurisdictions to develop adequate transportation plans.” The
Transportation study funded in the Governor’s 2013 budget has not yet begun.
When developing the scope of this study, the Departments should include the
“local jurisdictions” to assure compliance with the policies to be adopted. In
addition, there are several road projects under consideration (495 Truck Route) in
the region that will have impacts on truck traffic and early involvement in
developmental strategies at the state and local level would assure a unified
approach to that development.
The Executive Order requires the Departments to address “the risks of traffic
accidents and damage to roads and bridges from truck traffic related to drilling
operations.” The Departments, in consultation with the local jurisdictions, are
addressing these issues.
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10. All trucks associated with the development of a well permit must have GPS real
time spatial data to allow for tracking.
See response to comment #8. The GPS system will record both time and location.
11. As part of the CGDP, MDE should mandate trucking routes and haul times.
Truck routes and haul times will be addressed in the CGDP and specified in drilling
and operating permits.
12. The implementation and oversight of transportation and trucking to coordinate the
timing of oil and gas activities to avoid conflict and minimize damage to roads on
public lands is voluntary and thus unenforceable.
Once the transportation plan has been submitted and approved, it will be
incorporated into the permit. As a condition of the permit, it would be enforceable.
13. The discussion of road construction standards appears comprehensive. However,
the topic of who pays for public road maintenance is not addressed.
See response #3.
14. Trucks should be prohibited from hauling anything except during the following
times: 8:30 AM-4:30 PM, as not to disrupt the peace of the local community and
provide safe travel for school buses. In addition, the trucks should be prohibited
from traveling through sensitive areas, such as towns and schools, because of
hazardous risks.
A safe and efficient truck route will be part of the CGDP and individual permits.
School bus routes will be taken into account. Some towns and communities in
Allegany and Garrett Counties are on major traffic routes and experience significant
truck traffic, including trucks carrying coal, gasoline, propane and logs. These
probably involve as much risk as a truck hauling fresh water or wastewater from gas
operations.
15. The report recommends that the applicant enter into agreements with the local
government and or public land managers to maintain roads which it makes use of,
in the same or better condition prior to mining operations. Is this permitted by
State law? Would it be acceptable for the applicant to make repairs on public
roads? What options might be available for the community to collect funds from
the applicant and make the repairs themselves?
See response #3.
16. There appears to be a serious lack of regulation/enforcement regarding
transportation of volatile and dangerous materials (waste water) via trucks as they
navigate our rural roads and, in particular, towns and villages. BMP's should
include recommendations for truck routes, for example.
Hazardous materials transportation is regulated by the federal Department of
Transportation. Its requirements include such things as licensing of drivers,
packaging, and placarding. Truck routes will be addressed in the CGDP and
individual permits.
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WASTE DISPOSAL
1. General.
a. Waste disposal is problematic since there is no safe disposal method.
b. The report does little to address how fracking wastewater will be disposed
of in Maryland. In other states that failure to regulate wastewater disposal,
the underground injection of this toxic fluid has been linked to
earthquakes and contaminated drinking water.
c. The current permit does not address the disposal requirements for natural
gas development.
d. Tens of millions of gallons of toxic waste, as well as large amounts of
residual solid waste from the recycling process that would require safe
disposal. The report fails to address this problem.
The Departments acknowledge that waste disposal is an important issue. Waste
management and waste disposal are discussed in the draft best practices report in
Section VI.K and Section VII.
e. The waste from glycol dehydrators should be disposed of properly.
Existing law requires that all wastes be disposed of properly.
f. Provide for disposal of the water that returns from the well – laden with
sand, antibiotics, salts and sometimes radioactive material from miles
down in the earth.
g. The handling and disposal of radioactive wastewater and sludge needs to
be addressed.
This issue is discussed in the draft best practices report at VII.E. Cuttings, flowback,
residue from treatment of flowback and produced water, and any equipment where
scaling or sludge is likely to occur shall be tested for radioactivity and disposed of in
accordance with the law at a facility permitted to accept it. This would address both
naturally occurring radioactive material (NORM) and technologically enhanced
NORM (TENORM).
h. Accidental spills at handling facilities, leakage from trucks and railroad
tank cars, spillage due to human error, worn out equipment, wrecks, etc.
Furthermore, neither underground nor surface storage facilities are fully
foolproof, accident-proof, or earthquake proof. One way or another, an
unacceptable quantity of these chemicals will eventually end up in the
environment, “best practices” notwithstanding.
Human error and accidents are inevitable. The best practices seek to minimize the
chance that releases of pollutants will occur, to require containment of any spills that
occur on the pad, and mandate cleanup of spills.
i. A county not far north of where I live has taken to using diluted produced
water to melt roadway ice, and a mechanic our family knows states that
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the frequency of vehicles brought in for repairs following catastrophic
undercarriage/frame failure has gone up five- to ten-fold.
Produced water is high in salts, and it is not surprising that the uncontrolled or
excessive application of salty water to roadways could damage vehicles and the
environment.
2. Transportation and tracking of wastes.
a. Wells require 4 to 5 million gallons of fresh water to frack, multiply that
by 1000 wells and that by the 2 or 3 times a well will need to be refracked
in its lifetime and you have up to 20 billion gallons of hopelessly polluted
water that need to be disposed of. Piped or trucked out, some kind of
permitting and tracking of this waste is called for.
The current trend is for much of the flowback and produced water to be recycled.
The draft best practices report addresses tracking the production, shipment, and
disposal of this wastewater in Section VI.K.
b. Placarding and GPS tracking/logs should be required for all waste hauling
vehicles because of increased truck traffic carrying toxic fracking waste.
c. Since the waste is toxic all trucks/vehicles hauling the waste should be
well labeled and their routes logged. Placarding and GPS tracking/logs
should be required for all waste hauling vehicles because of increased
truck traffic carrying toxic fracking waste.
d. If those transporting this had tracking and kept logs as well as using tracer
chemicals to track illegally dumped water I might feel a bit safer.
e. Unique tracer chemicals should be included in fracking wastewater, so
that illegal dumpers can be more easily tracked.
f. The decision to not allow for waste disposal in Maryland is important and
requirements by the Departments for logging and identifying shipments,
materials being hauled, hauler, date, and name, address, shipment amount,
and date of the receiving facility are all critical to protecting Maryland’s
environment and the safety of its citizens. However, MAC believes that a
final requirement for this important process would be to add a real time
manifest reporting and a GPS truck tracking system to the process. The
lack of an effective monitoring system will like all other critical parts of
MSGD is a flaw that leads to the inability to detect and manage significant
problems when they occur.
g. The requirement that all drilling related trucks be equipped with
monitoring devices is an excellent idea. There must be official logging and
storage of this data during the drilling operations so the data can be
reviewed if there is a question of inappropriate disposal of waste products
or an accidental spillage.
The movement of hazardous materials is regulated by the United States Department
of Transportation, Pipeline and Hazardous Materials Safety Administration.
Hazardous materials include such things as explosives, flammable materials, poisons,
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oxidizers, infectious substances, and corrosive substances. If the material
transported qualifies as hazardous, the regulations address many aspects of the
handling, including packaging, placarding, shipping papers, and driver
qualifications. Placards provide a brief, generic description, and do not convey
detailed information on waste characteristics.
In order to assure that all wastes and wastewater are properly treated or disposed of,
regardless of whether they meet the definition of “hazardous” the best practices
report requires permittees to keep a record of the volumes of wastes and wastewater
generated on-site, the amount treated or recycled on-site, a record of each shipment
off-site and confirmation that the shipment arrived at the designated disposal facility.
In addition, all trucks, tankers and dump trucks transporting liquid or solid wastes
will be fitted with GPS tracking systems. These systems will record the location of the
vehicles over time. The records can be reviewed if there is a report of a spill or if the
shipping papers suggest that the wastes did not arrive at the designated facility.
A program for adding tracer chemicals to wastewater would be hard to design and
enforce, and would not necessarily make it any easier to detect illegal dumping. For
example, if wastewater were illegally discharged into a flowing stream, it would
likely travel a considerable distance and experience dilution before anyone noticed
and reported the spill. Samples from the stream might have such low levels of the
tracer chemical as to be undetectable. The draft best practices report addresses the
issue of illegal dumping by requiring that all trucks, tankers and dump trucks
transporting liquid or solid wastes be fitted with GPS tracking systems, and by
requiring recordkeeping of wastes shipped and confirmation that the waste was
received at the facility authorized to accept it.
3. Use of Class II injection wells.
a. MDE should consider eliminating Class II injection wells as a wastewater
disposal option.
Class II injection wells are currently the best option for disposal of wastewater from
HVHF.
b. Shouldn’t we consider all HVHF wells Class II UIC wells if waste is,
essentially, stored in them? If we are actually “storing” waste in every
well we drill, does it matter that our geology is not considered suitable for
this purpose?
In the broadest sense, a HVHF well could be considered an injection well because it
is a “well” into which “fluids” are being injected; however, it is not defined or
regulated this way. Production wells bring oil and gas to the surface; the UIC
Program does not regulate wells that are solely used for production. There are three
types of Class II injection wells: Enhanced Recovery Wells inject brine, water, steam,
polymers, or carbon dioxide into oil-bearing formations to recover residual oil and—
in some limited applications—natural gas; Disposal Wells inject brines and other
fluids associated with the production of oil and natural gas or natural gas storage
operations; and Hydrocarbon Storage Wells inject liquid hydrocarbons in
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underground formations (such as salt caverns) where they are stored, generally, as
part of the U.S. Strategic Petroleum Reserve.
4. Disposal in wastewater treatment plants (WWTPs), landfills and on-site.
a. Water from this industrial process should not be treated at a local sewage
treatment facility which is not equipped to handle these kinds of
chemicals.
b. Just like any other industrial activity, Maryland should prepare to permit
and regulate treatment and pretreatment of industrial waste from natural
gas drilling activity. I do believe that every publicly owned treatment plant
(POTW) and public WWTP is required to have pretreatment requirements
for any industrial discharge into the WWTP. The EPA rule for shale gas
wastewater if available by 2014 should be used as the standard for
pretreatment if discharges are to occur into a POTWs or public WWTPs.
Until these regulations are in place MDE should require that POTWs and
WWTPs not accept these wastewaters without prior consultation with
MDE.
c. Although EPA has committed to develop standards to ensure that
hydraulic fracturing wastewaters receives proper treatment and can be
properly handled by POTWs. However, their plan is not to propose rules
for wastewater until 2014. Until these regulations are in place, the
Agencies must create the most prohibitive practices and regulations on
disposal and/or treatment of hydraulic fracturing flowback.
d. Substances that are buried in the earth and come to the surface with the
fracking-released gases or fluids. They include toxic chemical salts, salts
of boron, cadmium, arsenic and a variety of heavy metals, including
radioactive ones. These salts cannot be disposed of by local wastewater
treatment plants, nor can they be safely consigned to regional landfills.
The EPA has successfully filed a number of suits against firms that have
attempted these ways of disposing of frack-induced undesirable salts.
MDE has taken appropriate steps to prevent the discharge of hydraulic fracturing
wastewaters to wastewater treatment plants. When EPA promulgates pretreatment
standards, MDE will consider whether any wastewater treatment plants in Maryland
should be allowed to treat that water.
e. Rock cuttings, about the size of coarse grains of sand, must be disposed of,
and they are coated with used drilling fluids that can contain contaminants
such as benzene, cadmium, arsenic, mercury and radium-226. These
wastes may present other problems for landfills, beyond radioactivity.
Non-liquid wastes may be disposed of in landfills. Maryland’s nonhazardous waste
landfills include liners designed to prevent the release of hazardous constituents from
the landfills. The landfills are also required to do routine groundwater monitoring to
detect any releases. Permits for the landfills establish limitations on what the
landfills may accept for disposal.
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f. For cuttings disposal, there is an unclear criteria that if the cuttings meet
other criteria established by MDE, then on site disposal of the cuttings
could be allowed. There is no information as to what the other criteria may
be. This means for planning purposes, all wells would require hauling off
of cuttings and the initial plan would include increased trucking to move
the cuttings. This creates an immediate bias in the plan and artificially
inflates the potential traffic from the drilling site.
g. Maryland should not permit onsite disposal of cuttings and drilling mud.
The draft best practices report stated: “The Departments agree that the cuttings and
drilling mud should be tested for radioactivity, but recommend that they also be
tested for other contaminants, including sulfates and salinity, before disposal. If the
cuttings show no elevated levels of radioactivity, and meet other criteria established
by MDE, onsite disposal of the cuttings could be allowed. Current regulations
provide “Land farming of cuttings shall be permitted only on approval from the
Department and shall require: (1) Soils analysis before site preparation; (2) Cuttings
analysis as directed by the Department; and (3) Post land farming soils analysis.”
COMAR 26.19.01.11W. The Department has not set criteria in advance, but MDE
has significant experience with land application of materials such as sludge from
wastewater treatment plants. The criteria could be site-specific.
5. Recycling.
a. Audubon further supports the proposed guideline for recycling 90 percent
of flowback and produced waters in subsequent drilling activities and for
the policy preference for on-site re-use.
b. While encouraging recycling and reuse of water is appropriate, the
requirement for 90 percent recycling “on the pad site of generation” is
unrealistic due to the number of inherent operational variables. To achieve
that high level of recycling can require use of specialized equipment that
not only requires additional space, but also needs enough volume throughput to be practicable. Allowing for transport of flow back and produced
waters to a centralized recycling facility has the potential to improve reuse
and recycling of the water. Again, this topic is covered in the API
recommended practices with respect to water use and reuse for hydraulic
fracturing operations.
c. The 90 percent water reuse is a sound goal which some companies are
already doing on some sites but this should not be a fixed requirement
which will allow companies to adapt to the appropriate conditions.
d. In addition to the risks of chemicals pumped into the ground, large
volumes of water return to the surface with the same chemicals, plus
radiotoxic brine. The Report calls for recycling of this water "to the
maximum extent practicable". This language is vague and leaves many
questions of risk: how is 'practicable' determined? How clean must the
'recycled' water be? What is done with the contaminants that are removed
in the water recycling? There are many such unresolved questions, and in
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most cases, there is a financial incentive to underestimate the long-term
costs and complications.
A percentage of the fracking fluid returns up the borehole to the surface; based on
information from Marcellus wells in other states, it is anticipated that about
30 percent of the water will return. The trend is to recycle this flowback for reuse in
another fracturing job. It needs to be as “clean” as necessary for reuse in HVHF.
Residuals from treatment must be disposed of in accordance with law. The flowback
that cannot be recycled is usually disposed of in Class II injection wells. There are
no such wells in Maryland. The waste is usually sent by truck. The best practices
report recommends a tracking system for wastes.
The Departments realize that it will not always be feasible to recycle flowback on
site, and the recommendation took this into account. The draft report said
“Flowback and produced water shall be recycled to the maximum extent practicable.
Unless the applicant can demonstrate that it is not practicable, the permit shall
require that not less than 90 percent of the flowback and produced water be recycled,
and that the recycling be performed on the pad site of generation.” Treatment at a
centralized treatment plant will require additional truck trips. The applicant for a
drilling permit must submit a plan for storage, treatment and disposal of water and
wastewater. The Department of the Environment will review that plan, and any claim
by the applicant that recycling is not practicable.
“Practicable” is a term often used in laws and regulations. It is used
interchangeably with “feasible” and describes an idea or activity that can be brought
to fruition or reality without unreasonable demands. In the draft Best Practices
report, “practicable” is often used in connection with a plan that, once approved,
becomes part of the permit. The approved plan, which will be incorporated into the
permit, will be specific as to the recycling and sufficiently clear to determine
compliance or noncompliance.
WATER USE
1. The amount of water needed is too great for the benefit.
Maryland law requires that proposed water uses be evaluated to ensure that 1) the
amount of water used is not wasteful for the proposed use, 2) the water use does not
cause unreasonable impacts to the water resource, and 3) the water use does not
cause unreasonable impacts to other users. Any request for water appropriation for
fracking would be subject to this analysis.
2. Every frack uses up to 4 million gallons of water. In the western states where
fracking continues, whole towns have run out of water. One frack in Maryland
would use about one day’s worth of water for the people living over the shale.
Fracking uses immense amounts of fresh water which is irreplaceable, and that
effect occurs even when other damage might (or might not) be successfully
minimized.
During a year with average precipitation, over 1.3 billion gallons of water falls on
Garrett County, on average, each day. The impact of a proposed water withdrawal is
evaluated based on its particular location, the rate of withdrawal and the duration of
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the withdrawal. It is difficult to generalize the impacts of water use, as each situation
is unique. MDE requires applicants to assess the impacts of their proposed use on
other users, conducts an independent evaluation of impacts and would not issue a
water appropriation permit for a use that would cause adverse impacts to a water
supply. Permits are written to ensure that impacts to the resource and other users are
not unreasonable, and permits contain conditions intended to prevent or mitigate any
impacts.
3. Maryland must revise its permitting regulations to address these water issues,
Maryland must require withdrawals be only from large rivers or reservoirs.
Maryland has robust regulations to appropriately manage requested water uses in
the State. Property owners have a legal right to use water on their property. Property
owners whose lands abut surface water bodies have a legal right to use water in
adjoining water bodies subject to conditions and protections imposed on the use by
MDE. Water appropriation and use permits are the mechanism to ensure that water
use is managed appropriately and that adverse impacts are prevented.
The commenter provides no guidance on how large a river must be to allow a water
withdrawal. A stream that is 10 feet wide, averages 6 inches deep and flows at 3 feet
per second would carry about 9.7 million gallons of water per day. If an applicant
requested to withdraw via a pump with a capacity of 500 gallons per minute, this
request represents about 8 percent of the stream flow during the instant of
withdrawal. Running the pump for about 6-7 hours per day for three weeks would
provide about 4 million gallons of water.
Withdrawal permits from any stream or river require that a minimum flow be left in
the river undisturbed. Maryland’s methods for determining the flow-by for new
withdrawals was not accurately described in the UMES-AL report. The required
flow-by is a natural flow that has a statistical probability of being exceeded
85 percent of the time during the period of the use at the location of the withdrawal.
During drought warning conditions (note, the drought warning trigger for streamflow
is a streamflow that is exceeded between 90 and 95 percent of the time) withdrawals
from a free flowing stream would be required to cease.
4. If there is a dry spell or water level decrease, the State should intermediately cut
off the water supply for fracking until the supply is deemed sufficient. Constant
monitoring should be done.
Permits for surface water withdrawal rely on long-term gage monitoring for
determination if adequate water is present to support a withdrawal. See response
above.
5. Given the massive amounts of water required to perform fracking, we wish to see
recommendations limiting water withdrawals to areas where more than an
"adequate reserve" is present such as reservoirs, lakes, and large rivers. "Adequate
reserve" needs to be operationally defined, and we support the UMCES
recommendation that MDE regulations be reviewed, and revised as necessary,
regarding water withdrawal. Members of our Board have observed trucks illegally
withdrawing water from Savage River, a premier brook trout stream, when water
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levels have been very low. Current water appropriation regulations are
insufficient to address this matter even without fracking. We recommend that
MDE establish a citizen reporting program for water withdrawals, and funding for
such an educational program must be budgeted, as well as additional MDE
enforcers.
While a large quantity of water is needed for an individual fracking operation, the
withdrawal may be spread out over an extended period of time and the rate of
withdrawal within the range of a moderately large appropriation permit. While not
generally recognized by the public, there is a much larger quantity of water stored in
underground aquifers than in surface water bodies. If the upper 800 feet of aquifers
in Garrett County contains fresh water and the average porosity of the consolidated
sedimentary rocks is 5 percent by volume, then the amount of water stored in the
aquifers in Garrett County is equivalent to a lake that is 40 feet deep over the full
area of the County. This groundwater reserve represents about 55 billion gallons of
water.
If Board members have observed what they believe to be illegal appropriations from
trucks, such incidents should be reported to MDE’s Water Supply Program. We
appreciate the expression of support for additional MDE staff for compliance and
enforcement duties.
6. Yet again the findings of UMCES-AL have been put aside by the BMPs. If the
current water appropriation regulations are stringent enough then why would the
study recommend that they be tightened?
The recommendation referred to is apparently “We found that Maryland’s current oil
and gas regulations governing permitting for conventional development require many
of the elements that would be needed to properly address MSGD or unconventional
development in general; however, the state should consider revising its oil and gas
permitting regulations to explicitly address water withdrawal and storage issues,
drilling waste and wastewater treatment and disposal issues, as well as
transportation planning issues.” The Department of the Environment has considered
revising its regulations and determined, for the reasons stated in the response to
comments, that revisions to water withdrawal regulations are not necessary, and that
it is not necessary to include water withdrawal provisions in the oil and gas
permitting regulations.
7. The study continues to rely on the Susquehanna River Basin Commission water
appropriation methodology to determine if sufficient ground and water surface
capacity exists in Allegany and Garrett Counties. There are significant differences
between water availability in the Appalachian basin than the remainder of
Maryland, and there may need to be changes in the Maryland appropriations
process to more adequately establish a set of best management practices for
Appalachian Maryland prior to allowing withdrawals for Marcellus gas drilling.
Changes include but are not limited to permitting, reporting and monitoring by
MDE personnel.
Existing water appropriation permitting law, regulation, and policy provide for
different types of evaluation based on the location and hydrogeology of the proposed
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withdrawal. Thorough hydrogeologic evaluation of permit requests is conducted, and
ongoing reporting is required for all large permits. The appropriation program does
rely on self-reporting, which has proven satisfactory in the past. If a more rigorous
oversight program is desired, a source of funding to support additional staff and
alternate methods of verifying water withdrawal information would be needed.
8. The Departments state that their requirements for water withdrawal permits are
sufficiently robust and therefore will retain their current procedures for permitting
water withdrawals. Water taken from local streams can jeopardize the habitat of
fish as well as requirements needed for macroinvertebrates. These concerns for
prudent water use sources are critical to the health of Maryland’s coldwater
resources. Given that the current procedure provide only limited public comment
on water withdrawal permits would, if we requested a hearing for each
application, become resource intensive and cumbersome as well as providing an
additional source of public contention that could be avoided by developing large
resource solutions for significant amounts of water needed over short time frames.
The Departments are aware of concerns about the impact of withdrawals on aquatic
species. Conditions to limit intake velocities and require screening for surface water
withdrawals are standard permit conditions for surface water withdrawals, along
with limiting the withdrawal rate, and requiring a stream flow-by. It is correct that
requesting a public hearing for each permit would require additional staff time and
increase the permit processing time. It may be advantageous for regional withdrawal
locations to be identified to limit the number and location of withdrawals. State law,
however requires that all contiguous property owners for proposed withdrawals
exceeding 10,000 gpd, as an annual average, be given an opportunity to comment on
a requested water use.
9. Maryland’s regulations for water withdrawal need to include a way to track
cumulative effects of natural gas development on regional water resources.
When making a decision to issue or renew a water appropriation permit, the
Department of the Environment considers the aggregate changes and cumulative
impact that this and future appropriations in an area may have on the waters of the
State, both surface water and groundwater. COMAR 26.17.06.05. Stream gages
represent the best opportunity for quantifying the impact of withdrawals over a
regional area. It may be necessary to install additional stream gages to appropriately
quantify impacts of withdrawals. Reporting of water use is a standard condition of
permits and the reported water use can readily be tabulated by use type and or
location to determine withdrawal quantities for specific periods of time in different
watersheds.
10. The requirement that all drilling related trucks be equipped with monitoring
devices is an excellent idea. There must be official logging and storage of this
data during the drilling operations so the data can be reviewed if there is a
question of inappropriate water acquisition.
The draft best practices report made this recommendation with respect to trucks that
were transporting liquid or solid wastes, not fresh water. Except for subdivisions
served by individual domestic wells, a permit issued for an average of 10,000 or more
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gallons a day must contain a condition requiring the permittee to report semiannually
to MDE the quantity of water appropriated under the permit for each of the preceding
6 months. MDE may require a permittee to report daily use and may require the
permittee to install flow-measuring devices. COMAR 26.17.06.06. MDE will
consider including a permit provision requiring recordkeeping and reporting of fresh
water transportation.
11. The regulation of water withdrawal strictly for human use may disregard the
ecological flow requirements of species that occur in those waters. We would
encourage MDE and DNR to review current policies and regulations to ensure
that water withdrawals for HVHF also protect the ecological flow requirements of
plant and animal species that use waters of the State that might experience HVHF.
Existing water appropriation laws, regulations, and policies already take into
account water needs for aquatic habitat. Evaluation of groundwater withdrawals
take into account baseflow needs for streams, and surface water permits include a
requirement that withdrawals cease if flows fall below a specified level. Permits also
include other conditions, such as requirements for screening of intakes, that are
intended to protect aquatic species. MDE routinely provides DNR the opportunity to
review and provide input on surface water permits. Identifying funding to continue
and complete the Fractured Rock Water Supply study could provide additional
information that would assist the Departments in making better decisions regarding
permit requests.
12. As with transportation, the current API recommendations address water
withdrawal and usage should be evaluated by the state in the development of final
recommendations.
API Guidance Document HF2, Water Management Associated with Hydraulic
Fracturing, would be considered a “relevant” API standard for purposes of the plans
to be submitted with each individual well.
13. Fees and monitoring.
a. The departments should adopt the water appropriations standards of the
Susquehanna River Basin Commission (SRBC) for appropriations and fees.
The SRBC fee structure allows for stream monitoring from areas where water
withdraws are likely to impact water turbidity, ph, and temperature.
b. There is no fee for a water appropriations request. However, this may prove to
be a very time consuming endeavor for MDE, which may backlog the current
18-month turnaround for permits of over 10,000 gallons per day. Permit fees
with the SRBC (which MDE partners with) allow for water monitoring from
identified specific sites of surface water.
MDE agrees that imposing a fee for water appropriation permits would be
appropriate. The fee structure needs to be based on Maryland’s needs and would not
necessarily follow the SRBC model. Several bills have been proposed over the years
to establish a fee system, but none passed. In addition, MDE has met with
stakeholders to try to negotiate a fee structure that would be appropriate for all
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users; however this effort has not met with any success or agreement from the
stakeholders.
The fairly long time frame for issuing a large permit is primarily the time needed for
the applicant to address the technical issues in the detailed permit application
requirements. Addressing issues from the public can extend the time to complete a
permit decision. Once instituted, a fee structure should not have any impact on the
amount of time that it takes to issue a permit (unless the applicant is late in paying
the fee.) Fee legislation would establish the purposes to which permit fees could be
used.
14. Currently there are no provisions within the permitting structure to track water
appropriations requests from parent companies, subsidiaries, or subcontractors for
multiple permit requests.
While it’s true that each water appropriation request is considered separately, MDE
is currently in the process of developing a new data management system for water
appropriation permitting that will allow the Department to better track related
permits.
15. There is no provision for the multi-well CGDP process.
Water appropriation permits are issued separately from either CGDP approval or
issuance of a permit for an individual well. The water appropriation application
should identify the amount of water needed and the need for it. A water appropriation
permit could be issued to supply water for multiple wells. The Departments plan to
add a provision to the CGDP that would require the applicant to provide information
on how it intends to acquire the necessary water.
16. Under the current system municipalities with a permit are not required to report to
MDE withdrawals sold to companies for MSGD, as long as they do not exceed
the permit threshold. This gap needs to be addressed to track cumulative effects of
natural gas development on regional water resources.
The cumulative effect of water withdrawals on regional water resources is not
tracked on an industry-by-industry basis. The water appropriation permit does not
limit the permittee’s ability to sell water, but upon permit renewal, or even earlier,
MDE could reevaluate the permittee’s allocation.
17. We support the Appalachian Lab report which recommended that Maryland revise
its permitting regulations to address water withdrawal issues, by requiring
withdrawals only from large rivers or reservoirs.
See previous answers.
18. Drilling companies should have to purchase the surface water used – much of this
water does not return to the surface water cycle.
Before issuing a permit, MDE considers whether the water is returned to the
watershed or used consumptively; however, there are currently no requirements that
water users pay a consumptive water use fee. If a drilling company obtains water
from a community water system, the company would likely pay a fee that is at least
equivalent to the cost to the water system of producing the water.
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19. The report should include a provision for encouraging usage of acidic coal mining
discharges and or treated acid mine water for drilling purposes.
Existing water appropriation permit policies require certain applicants to evaluate
the feasible use of alternate water sources before a groundwater withdrawal would
be approved. This would apply to companies seeking to use water for hydraulic
fracturing. Alternatives to encourage prior use of natural waters could include reuse
of fracking water, using reclaimed municipal or industrial wastewater and acid mine
drainage (AMD). There are liability issues related to the use of AMD which act as a
disincentive to using AMD. In the future, the Department of the Environment may
consider how it might address these liability issues.
20. If private wells run dry because water is taken for fracking, will those citizens be
provided with potable water from deeper wells?
If the initial testing of a well for water production (as would be required during the
application process for a large groundwater withdrawal) showed that a homeowner’s
well would be adversely impacted, such that it would no longer produce the needed
quantity of water, then the applicant would be required to either locate the
production well in a different location or improve the impacted supply before the
applicant would be allowed to withdraw any water. Standard permit conditions
would require a large groundwater user to cease pumping if their use caused a
nearby well to run dry. Anyone impacted by another water user should notify the
Water Supply Program immediately. An investigation would need to be initiated to
determine if the lack of water from the well was from a lowered water level and not a
defective pump or other mechanical/electrical issue. The permit would also require
the permittee to provide at no expense to the homeowner an interim water supply and
a permanent replacement water supply, if needed. It may be possible to alleviate an
impact by reducing the withdrawal rate or by drilling a deeper well for the private
well owner.
WELL CASING AND CEMENT
1. When wells or casings or cement fails, fracking fluid, flowback, and methane can
be released. The following failure rates have been reported:
a. 5 or 6 percent of the time.
b. Industry studies find up to 60 percent will fail after 30 years.
c. PA reports a 7.2 percent failure rate.
d. EPA reports at 8.9 percent well casing failure rate for 2012, and a
7.1 percent failure rate in 2011 in Pennsylvania.
e. Maryland needs to find a way to adopt a standard that allows for 0 percent
failure upon installation of casing.
f. The stats regarding casing failure show that currently zero leakage, which
should be required but is not under the proposed BMPs, is impossible.
If the casing and cement fail to completely isolate a gas well from the formations
through which it passes before reaching the target formation, gas can migrate from
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intervening gas-bearing formations and can enter the environment, including
drinking water aquifers. Not every failure of casing or cement results in a release of
methane or other contaminants. For example, a tubing or packer leak inside of casing
is technically a failure, but the pressure is still contained within the casing and no
methane escapes from the well. Nevertheless, casing or cement failures should be
avoided and, if they occur, promptly addressed.
Some of the best practices in the draft report are directed to assuring that the casing
and cement will be properly installed and tested. These have been strengthened in the
final best practices report by explicitly requiring that the applicant submit a plan that
describes:
a. how the a stable borehole will be drilled with minimal rugosity40;
b. how complete removal of drilling fluid will be accomplished;
c. how the cement system design addresses challenges to zonal isolation; and
d. how the casing and cement assure durability throughout the well life cycle.
This plan can be submitted with the permit application, but the permittee must review
the plan in light of information obtained from the pilot hole drilled for that well pad,
and certify to the Department of the Environment that the plan utilizes the right
practices and materials for the specific situation to assure zonal isolation. Before
commencing hydraulic fracturing, the permittee must certify the sufficiency of the
zonal isolation with supporting data in the form of well logs, pressure test results,
and other appropriate data. Adherence to the drilling, casing and cementing plan,
coupled with integrity testing, should also address the possibility that releases of
fracking fluid, flowback could occur because of casing or cement failure.
Although no activities can be guaranteed to have a zero rate of failure indefinitely
and under all circumstances, the Departments are proposing standards that will drive
down the failure rate and the consequences of any failure that may still occur. In
addition, through review and approval of the plan, the Departments can require
applicants to use better drilling, casing and cementing systems as they become
available. There is no single practice that will eliminate the risk of methane
migration; rather the Departments are proposing a combination of setbacks,
appropriate best practices, integrity testing, rigorous
monitoring/inspections/enforcement, timely identification and correction of problems
and mitigation if methane contamination should occur.
2. The causes of well failure should be addressed
a. We recommend that current industry standards be exceeded for pipeline
construction and well casings. Maryland should either come up with best
practices for minimizing the long-term degradation of the oil and gas
industry’s wells, or propose best practices for monitoring and resealing
degraded wells.
40
Rugosity refers to the roughness of a borehole wall. Rugosity can be observed on caliper logs and image logs Source:
Schlumberger Oil Glossary. High rugosity can make it more difficult to remove the drilling fluid and achieve zonal isolation with
cement.
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b. The industry, in consultation with the Agencies, should be required to
address the causes of casing integrity failure and to propose better
practices that continually improve its standards for casing integrity.
As noted above, the applicant will have to design the casing and cement to assure
durability for all anticipated conditions throughout the well life cycle. This will
require consideration of changes in temperature and pressure, and the effect of
refracturing the well and the installation and hydraulic fracturing of other wells on
the same pad. By requiring detailed plans from the applicant, the Department of the
Environment will require applicants to use better drilling, casing and cementing
systems as they become available.
3. Companies should be required to run a test on every well to ensure adequate
cementing, and inspections to ensure the compliance must be paramount if
drilling is permitted.
The regulations will require testing of every well to ensure adequate cementing
including cement testing, casing pressure testing, and cement placement verification.
Permit fees will be set at a level that supports a rigorous inspection and enforcement
program.
4. The recommendation calls for the production casing to be run the entire length of
the well and cemented. This requirement does not appear to allow for the use of
production liners and tie backs, and would also appear to require cementing the
entire production casing back to surface. Requiring cementing of the entire
production casing back to surface will create a number of design challenges that
may actually reduce the effectiveness of the cement seal. Bringing cement from
the total well depth back to surface could require the use of cements with very
long fluid times (pump times) that would result in a delay of the set of the cement
at the lower temperatures near surface. Cementing back to surface also eliminates
the potential to monitor annular pressures between the production casing and
intermediate casing, a needed safety measure during fracturing operations. The
recommendation should clarify isolation in the production casing, allow for use of
liner and tie back technologies, and better define what is meant by the statement
referencing cementing.
The recommendation will be clarified. Liners and tiebacks may be used, provided the
exposed casing meets all regulatory requirements for casing.
Surface casing must be set to a depth that isolates all freshwater formations and must
be cemented to the surface. Intermediate casing, if used, must isolate all fluid bearing
zones through which it passes. Intermediate casing, if used, must be cemented to the
surface unless the Department of the Environment approves an alternative.
Production casing must be cemented along the horizontal portion of the well bore
and to at least 500 feet above the highest formation where hydraulic fracturing will
be performed, or 500 feet above the uppermost fluid bearing formation not already
isolated by surface casing or intermediate casing, whichever is shallower. In this
way, casing and cement will isolate all fluid-bearing (gas and liquid) formations
through which the borehole passes before reaching the target formation, but it will be
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possible to monitor annular pressure, which provides the operator with valuable
information.
5. The recommendation is for the use of a segmented radial cement bond log
(SRCBL) rather than the conventional omnidirectional cement bond log (CBL),
but there is no statement regarding which casing strings would be required to be
tested by SRCBL. This should be clarified. Further, there is no provision for the
evaluation and analysis of the SRCBL, or who would determine the effectiveness
of the cementing operation. It is noted there are no recommendations for
capturing data during the cementing operation that would supplement the logging
operation.
SRCBL will be required for all casing strings from the surface casing and below
along the portions that are cemented. This can be supplemented by other methods,
including omnidirectional cement bond logging and observations and measurements
during cementing. If there is evidence of inadequate casing integrity or cement
integrity, the Department of the Environment should be notified and remedial action
should be proposed.
6. The incorporation of API Standard 65-2 would address cement evaluation in its
full form, using surface data during the cement job, laboratory design data as well
as post job logging information. The Standard correctly notes that one single data
point (or data set) should be used to make the evaluation of cement isolation.
The draft best practices report stated that, in developing the plan for the individual
well to submit with the application “the applicant shall consider API Standards and
Guidance Documents, and, if the plan fails to follow a normative element of a
relevant API standard, the plan must explain why and demonstrate that the plan is at
least as protective as the normative element.” API Standard 65-2 would be
considered a relevant API standard. The Departments acknowledge that evaluating
zonal isolation and cement integrity requires the consideration of more than one type
of data.
7. Maryland regulations should include more detailed requirements for timing of the
casing construction so that the process and monitoring can be completed
consecutively during one work shift. Reports from rig workers in Pennsylvania
have stated that casing cure times have been shortened in order to accommodate
work shift schedules, thus compromising the integrity of the cement strength.
It is not always possible to complete a stage of work within one work shift. For
example, the draft best practices stated: “The cement shall be allowed to set at static
balance or under pressure for a minimum of 12 hours and must have reached a
compressive strength of at least 500 psi before drilling the plug, or initiating any
integrity testing.” Applicants for permits will be required to submit a communications
plan that includes procedures to maximize continuity when shift changes or crew
changes occur.
8. Maryland should forbid the use of reconditioned casing.
The Department of the Environment will allow use of reconditioned casing only if it
meets required technical specifications.
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9. The method for testing the cement for compressive strength of 500 psi within 12
hours should be specified.
API Recommended Practice 10B-2, Recommended Practice for Testing Well
Cements would be considered a relevant API standard. Any recognized method, such
as ASTM C 109, Standard test method for compressive strength of hydraulic cement
mortars (using 2 in. or [50 mm] cube specimens), would be acceptable.
10. When a log (e.g., SRCBL) shows a failure, corrective action should be specified.
The Departments acknowledge that evaluating zonal isolation and cement integrity
requires the consideration of more than one type of data. If there is evidence of
inadequate casing integrity or cement integrity, the Department of the Environment
must be notified and remedial action must be proposed. The type of corrective action
cannot be identified in advance because the appropriate corrective action will depend
on the location and magnitude of the failure.
.
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APPENDIX D – MARCELLUS SHALE CONSTRAINT ANALYSIS
This analysis was conducted by the Maryland Department of Natural Resources to
estimate the potential effect that certain surface and subsurface constraint factors would
have on the ability to access Marcellus shale gas deposits. The Department understands
that there are many other additional factors that would also have an influence. This
estimate is to be used only as a preliminary assessment.
Surface and Subsurface Constraint Factors: Factors selected were those that support a
landscape scale analysis and were determined to be reasonable based on joint DNR/MDE
review of recommendations provided by UMCES. Fine-scale features, such as caves, the
down-dip side of limestone outcrops and private drinking water wells, were not selected
because complete data sets were not available. In addition, constraints associated with
these factors will be most relevant at a field scale site assessment.
Off-Limit Areas
Setback/Buffers
Type
Aquatic habitat
 streams, rivers, seeps, springs
wetlands, lakes, ponds, reservoirs
 100 year floodplains
450 feet
Surface
Special conservation areas
 Wildlands
 Irreplaceable Natural Areas
600 feet
Surface
Cultural, historical and recreational areas
 National Registry sites
 State and Federal Parks
 Trails
 Wildlife Management Areas
 Scenic and Wild Rivers
 Scenic Byways
300 feet
Surface
All Other DNR Public Lands
 State Forests
 Natural Resource Management Areas
 Others
0 feet
Surface
Deep Creek Lake
2,000 feet
Surface
D-1
Low, Medium and High Density Residential
and Institutional Uses (MDP 2010)
0 feet
Surface
Accident Dome Gas Storage Field
0 feet
Subsurface
 15 percent slopes (UMCES)
0 feet
Surface
Drinking water reservoir watersheds
(Broadford Lake, Piney Reservoir, Savage
Reservoir)
0 feet
Surface
Wellhead protection area or source water
assessment area for a Public Water System
1000 feet
Surface
Map A identifies the areas constrained from surface development and shows only the
surface constraints. These surface constraints (without any prohibition of well pad
development over the Accident Gas Storage field) remove 83.2 percent of the land
surface within the Garret and Allegany county Marcellus Shale exploration area from
surface development, leaving 16.8 percent of the land area available. Map B shows the
same information, but also includes the constraints on well pad development over the
Accident Gas Storage Field. With the constraints associated with the Accident Field,
84.7 percent of the land surface is removed from development, leaving 15.3 percent of
the exploration area available for surface development.
Subsurface Access Analysis
Based on the surface constraints identified above, the ability to access Marcellus shale
gas deposits through horizontal drilling was evaluated based on the UMCES statement
that each well could be drilled horizontally a distance of 8,000 feet. The analysis also
assumed that an average of 4 acres would be required for a multi-well pad based on
industry estimates published in the New York Revised Draft Supplemental Generic
Environmental Impact Statement (2011).41 Any areas less than 4 acres that remained
suitable for surface development were removed from the analysis since these locations
would not be large enough to support a pad. The remaining areas were buffered by 8,000
feet in order to determine the extent of Marcellus shale that was accessible. Map C,
which does not restrict access to the Accident Gas Storage Field shows that 94.1 percent
of the Marcellus shale can be accessed under this constraint analysis. A more
conservative analysis, using a 4,000 foot horizontal length, could provide access to
86.3 percent of the Marcellus shale. Map D provides a similar assessment, but does
restrict access to the Accident Gas Storage Field. Under this scenario, considering an
8,000 foot horizontal drill length, 88.0 percent f the Marcellus shale is accessible, while
80.2 percent is accessible using 4,000 foot horizontal drill length assumption.
41
www.dec.ny.gov/energy/75370.html.
D-2
D-1
D-2
D-3
D-4
APPENDIX E – MARCELLUS SHALE AND RECREATIONAL AND AESTHETIC
RESOURCES IN WESTERN MARYLAND
Marcellus Shale, State Lands and Economic Impacts of Parks
Maryland’s Western Region is rich in recreational, cultural and aesthetic resources.
Garrett and Allegany Counties are home to eight State Parks; one Natural Resources
Management Area (NRMA); one Natural Environment Area (NEA) – the State’s only
designated wild river, four State Forests; four Wildlife Management Areas, three fish
hatcheries/fish management areas, six Heritage Conservation Fund sites, one
undesignated conservation area (MET), two scenic byways; miles of trails and a number
of developed or developing water trails. Western Maryland has high public land visitation
by both day use and overnight users. The development of a Marcellus shale gas industry
in western Maryland has the potential to affect visitor’s experiences, alter the recreational
and aesthetic landscape of the region, negatively affect longstanding research and
resource management sites and change the economic impact of park visitation in the
future.
The Maryland State Parks are an economic driver for local communities and areas around
the parks (Dougherty, 2011)42. Of the four park regions in the State, those in the Western
region experience the highest overall economic benefit both in terms of direct spending
and total economic impact that considers indirect and induced effects (Figure 1, below).
State Park visitors in the Western region directly spend more than $211 million annually
during their trips. The Western region also experiences the second-highest employment
impact as a result of parks by supporting 2,775 direct jobs related to park visitation. Id.
Direct Spending
Region visited
Western
Central
Southern
Eastern
in MD
within a20
minute drive
Total Economic Impact
including indirect/induced effects
within a 20
in MD
minute drive
$211,407,422
$152,722,509
$239,273,592
$169,903,045
$74,297,143
$53,910,981
$86,879,793
$64,157,303
$76,994,613
$50,530,556
$88,065,924
$56,798,719
$204,743,180
$140,054,190
$236,445,765
$159,830,604
Figure 1. Total trip spending profile by region (Dougherty, 2011)
42
www.dnr.state.md.us/publiclands/pdfs/economicimpactstudy2010.pdf.
E-1
Open Space Experience
In the same Economic Impact Study (Dougherty, 2011), natural scenery was the most
highly rated attribute of a Maryland State Park experience for both day use and overnight
park visitors. The majority of activities that both of these user communities identified as
activities that they participate in at parks include hiking/walking, general relaxation,
swimming, picnicking/cookout, sightseeing and photography.
Byways, Hiking, Water Trails, Hunting and Fishing
Maryland has a number of well-developed and nationally-recognized networks of scenic
and historic byways and hiking and water trails that provide opportunities for the public
to experience nature, cultural and historical features and the outdoors through unique
vistas and long-distance travel routes. The location and features that make these routes
unique (e.g. vistas, through-trail hikes, canopy cover) should be considered during
setback discussions.
In addition to vast scenic values and hiking and water-based recreation, there are also
many opportunities for citizens to enjoy hunting and fishing on public lands in Western
Maryland. Especially for these groups, noise and other possible environmental effects
from drilling and operations can impact the quality or feasibility of these activities. If
wildlife is impacted or frightened away from a particular area, the potential exists for the
activity to be dislocated entirely.
Recommended Setbacks and Considerations
Currently, a proposed recreational setback from Marcellus shale gas infrastructure is a
minimum of 300 feet with additional setback considerations for noise, visual impacts and
public safety. In addition to these considerations odors, light and illumination from the
same infrastructure can also affect the natural and recreational values of areas of Western
Maryland.
Discussions with Maryland Department of Natural Resource (DNR) staff related to these
additional considerations, have identified several factors that may influence where this
minimum setback should be increased, in some cases significantly. For instance,
additional consideration and thought should be given for whether this setback should be
altered based on the following:
● whether the facilities at sites are concentrated or more spread out;
● locations of high-use where visitors, managers and community members identify
as most heavily trafficked or utilized;
● the presence or absence of natural buffers that could buffer sound, light and odors,
especially at night, and near campgrounds;
● areas where reduced-light recreation activities occur;
● areas where particular trails are most frequently identified as providing a peaceful
experience and that may be most affected by shale gas operations noise;
● lands or aquatic areas where natural resources may be degraded to a point that
park visitation for the purpose of enjoying those resources would no longer be
attractive;
E-2
● hunting areas that could be affected by access or operations noise and/or locations
where proximity to shale gas infrastructure would increase risk to site
operators/operations;
● whether unique designations are in place (e.g. Wild and Scenic Rivers) that define
an experience in a particular location or influence funding; and
● instances where public safety risks on or around State lands would be most likely
to be increased on roads, day use or overnight accommodation areas or in
surrounding areas as a result of close proximity of infrastructure and people.
To more thoroughly evaluate each of these and identify particular areas that may most
need additional setback consideration, work could be conducted with facility managers,
friends groups or small groups of frequent visitors to compile existing data and develop
new maps of use areas. In addition, some of these considerations could be considered on
a case-by-case basis during the siting process to determine their applicability and evaluate
what recreational or aesthetic uses that might be affected in a given area.
Night Skies
In Pennsylvania, where the Marcellus shale gas industry is much more developed, efforts
are underway to document the relationship between lighting on these industrial sites and
changes in the darkness of night skies. In particular, a group is working at Cherry Springs
Park in Potter County to document the proximity of the lights and potential impacts on
dark skies. In areas where there are dark night skies in western region State lands and
where reduced-light recreation activities occur, work should focus on how to keep those
night skies as dark as possible. Information and lessons learned can also be gleaned from
efforts such as the one that is ongoing in Cherry Springs.
Outreach & Community Engagement
Over the past five years or more, property owners and communities in western region
counties have become increasingly familiar with the development of the Marcellus shale
gas energy industry. In some cases, property owners have entered into lease agreements
with development companies for gas extraction. Since Maryland established its Marcellus
Shale Advisory Commission the public has had a periodic forum to learn what the State
is doing to plan for industry development; evaluate potential community, economic,
infrastructure, and natural resource impacts; and, set up a regulatory framework to ensure
safe and efficient development of the industry in Maryland.
State agencies and other partners have developed a number of resources to help citizens
better understand Marcellus shale gas site development. These include information43
from the Maryland Geological Survey, MDE’s Marcellus shale website44 and
publications45 from the Office of the Attorney General. The Maryland Department of
Natural Resources has extensive experience in public engagement on a variety of issues
and can recommend forum structures, information format and organizational approaches
for such events.
43
www.mgs.md.gov/
www.mde.state.md.us/programs/Land/mining/marcellus/Pages/index.aspx
45
www.oag.state.md.us/Environment/MS_leasing.pdf
44
E-3
The November 2013 Participatory GIS Workshop
On November 15, 2013 a participatory mapping workshop was conducted at Garrett
College to identify particular areas where recreational and aesthetic impacts would most
likely intersect with the expansion of the shale gas industry. The individuals invited to
attend were those engaged in some aspect of outdoor recreational use, either as a business
(tour guides, outdoor recreational services and retail), non-profit (birding, hiking,
environmental or other organizations), educational, or DNR public lands representatives
(rangers, park managers, Natural Resource Police).
These individuals were asked to work together and collectively map out areas within
Garrett and Allegany counties that were important for a variety of recreational uses.
Recreational use categories included 1) Recreational Guided and Outfitted Uses, 2)
Recreational Fishing and Hunting Uses, and 3) General Non-consumptive Recreational
Uses, such as boating, hiking, biking, etc. The exercise required participants to use a
large digital projection screen and digital pen to map out areas of high use according to
specific recreational uses as shown below.
The products from this mapping workshop are still under DNR review as of June 2014
and will be distributed to the participants for additional revisions if needed before the
maps are finalized. These mapping products will be included in the Shale Gas
Development Toolbox to be used during the Comprehensive Gas Development Planning
process in order to minimize public use conflicts resulting from shale gas development.
E-4
APPENDIX F – UMCES-AL REPORT AND CROSS REFERENCES
The UMCES-AL Report can be found at
http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Eshleman_El
more_Final_BMP_Report_22113_Red.pdf
Recommendations from the UMCES-AL Report with Analogous Provisions of Draft
Agency BMP Report
Chapter 1 – General, planning and permitting BMPs
UMCES-AL
MDE and DNR
1-A
Pre-development environmental assessment
should be conducted on a site-specific basis and
include: (1) identification of all on-site drilling
hazards such as underground mine workings,
orphaned gas or oil wells, caves, caverns, Karst
features, etc.; (2) identification of all ecological,
recreational, historical, and cultural resources in the
vicinity of a proposed site (includes well pad and all
ancillary development such as cleared areas around a
well pad, roads, bridges, culverts, compressor
stations, pipelines, etc.); (3) identification of the
appropriate setbacks and buffers for the proposed
site; and (4) collection of two years of predevelopment baseline data on underground drinking
water, surface water, and both aquatic and terrestrial
ecological resources.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation. Some of the data will
be required for the CGDP; other data in
applications for individual permits. This
recommendation is also reflected in
Sections V, Plan For Each Well and VII,
Monitoring, Recordkeeping and
Reporting.
1-B
Maryland should require as part of its permit
application at least two years of site specific data
collection prior to any site development that would
be used to characterize the resources at risk and
provide a solid baseline dataset that would ultimately
be used to understand process and feedback to the
refinement of BMPs.
Section VII, Monitoring, Recordkeeping
and Reporting adopts this
recommendation and adds that
characterization and monitoring data will
be important to identify whether any
impacts to the resources has occurred,
and can be used as basis for mitigating
damage.
1-C
Comprehensive planning (a.k.a.,
comprehensive drilling plans) could potentially be
used to effectively channel MSGD into areas that
would be less sensitive to impacts while allowing for
considerable and efficient exploitation of the gas
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation; however, limiting the
disturbance to 1-2 percent of the land
appears as a planning principle for high
F-1
resource. Spacing multiwall pads in clusters—as far
apart as is technically feasible—makes maximum
use of horizontal drilling technology and could be an
important BMP in terms of minimizing development
impacts. With careful and thoughtful planning (e.g.,
co-location of infrastructure wherever possible), it
may be possible to develop much of the gas resource
in a way that disturbs less than 1-2 percent of the
land surface, even when accounting for the need for
ancillary infrastructure such as access roads,
pipelines, and compressor facilities. Comprehensive
gas development plans could also moderate the rate
at which the resource is developed in Maryland, thus
allowing the regulatory enforcement arm of MDE
(with little recent experience in gas well permitting
and no experience in unconventional gas) to ramp up
over time.
value watersheds and the Departments do
not recommend using CGDPs to limit the
pace of development.
1-D Maryland should consider legislation that
would enable the state to implement “forced
pooling” as a way of providing greater resource
protection while allowing for efficient resource
exploitation.
Section VIII C, Miscellaneous
Recommendations. The Departments
recommend that forced pooling not be
considered at this time.
1-E
Maryland should impose by regulation
sensible setbacks (see Table 1.1) that are adequate to
protect public safety, as well as ecological,
recreational, historical, cultural, and aesthetic
resources.
Section IV A, Location Restrictions and
Setbacks. The Departments generally
accept the proposed location restrictions
and setbacks with the exceptions noted.
The Departments reduced the suggested
setback from limestone outcrops,
increased the setback from aquatic
habitats, private ground water wells,
public water systems and reservoirs,
excluded development on all DNR public
lands, and require pre-drilling planning
including geologic investigations and use
of pilot holes to evaluate subsurface
hazards, such as deep coal mines, gas
wells, faults, etc.
1-F
There is a definite need for an analysis of
extant hydrogeological data from western Maryland
that could be used to develop flow nets or models
and infer ground water flowpaths and other
important features such as recharge areas, discharge
areas, hydrologic residence times, and depth of the
freshwater zone across the area.
The Departments, with the help of
Garrett County, have begun to assemble
the existing data on drinking water wells
in Garrett County and undertaken
additional ground water sampling.
F-2
1-G Maryland might consider developing a
standardized stakeholder process that could be
implemented as part of comprehensive planning
strategy; the goal of such a process while allowing
the permit review process to be expedited.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
1-H We recommend that Maryland follow
guidance from New York’s experience with
unconventional shale gas development and
effectively not permit MSGD (or any other
unconventional gas development) where the target
formation occurs within 1,000 vertical feet of
USDW or within 2,000 vertical feet of the ground
surface. Since the freshwater/saltwater interface has
not been mapped in Maryland, the prudent approach
would be to rely on the 2,000 ft criterion to provide
an adequate margin of safety.
This recommendation is accepted in
Section IV A, Location Restrictions and
Setbacks.
1-I
An obvious best practice would be to site
well pads so as to avoid vertical drilling ( i.e.,
surface boreholes) in areas where shallow caves and
caverns have been mapped or where there is a high
probability that such systems might be present.
Maryland should develop a GIS map system of both
active and abandoned oil and gas wells (including
gas storage wells) and active and abandoned coal
mine workings prior to permitting any new
Marcellus wells; all underground hazards with ¼
mile of any section of a proposed Marcellus well
should be identified as part of the permit review
process and avoided wherever possible.
Section IV A, Location Restrictions and
Setbacks. The Departments generally
accept the proposed location restrictions
and setbacks recommendations and will
develop a Shale Development Toolbox to
provide a comprehensive set of GIS
planning data, including known and
mapped locations of the features listed in
this recommendation.
1-J
Maryland should require a 1,000 ft setback
from all deep mine workings and ¼ mile setback
from all historic gas wells. The gas well setback
should be measured from any portion of the borehole
(vertical or horizontal) to the historic well.
Section IV A, Location Restrictions and
Setbacks. The Departments recommend
reducing the 1,000 ft setback from deep
mine workings as it is unnecessarily
restrictive since Maryland’s deep coal
mines may cover thousands of acres, are
only several hundred feet deep, and can
be safely cased through, particularly if
pilot holes are drilled to identify these
features and drilling processes are
modified to address the known hazards.
Section VI D, Engineering, Design and
Environmental Controls and Standards
require pre-drill planning to plan for and
avoid, if necessary, subsurface hazards
1-K
Section VI R, Engineering, Design and
Maryland should develop regulations that
F-3
force rapid partial reclamation (including
revegetating disturbed areas surrounding wells pads,
corridors, and ancillary infrastructure) of all land not
needed for drilling and production as quickly as
possible, while allowing the remaining portion to
exist unreclaimed only until such time as drilling is
completed, production ends, and final reclamation
can be performed.
Environmental Controls and Standards
adopt this recommendation
1-L
We found that Maryland’s current oil and gas
regulations governing permitting for conventional
development require many of the elements that
would be needed to properly address MSGD or
unconventional development in general; however,
the state should consider revising its oil and gas
permitting regulations to explicitly address water
withdrawal and storage issues, drilling waste and
wastewater treatment and disposal issues, as well as
transportation planning issues.
MDE considered the need to revise the
oil and gas permitting regulations.
Recommendations for changes can be
found throughout Section VI,
Engineering, Design and Environmental
Controls and Standards.
1-M Local zoning ordinances for both counties
should be amended to spell out in which zoning
districts MSGD would be permitted as a way of
minimizing some of the major conflicts and public
safety issues that we addressed in this report.
Section VIII A, Miscellaneous
Recommendations. Zoning is a local
matter over which the State has no
control. The Counties are well aware of
their authority to enact zoning
regulations.
1-N Maryland’s requirements for performance
bonding under current regulations ($100,000 per
well or $500,000 blanket bond for all of an
applicant’s wells) are relatively high compared to
other states; thus, the state might be to avoid some of
the problems associated with divestment of MSGD
assets from primary to secondary firms that are
predicted as gas production declines. Nonetheless,
Maryland might want to consider alternate
mechanisms of covering decommissioning and
reclamation costs through a trust fund mechanism (
i.e., investing revenue from pre-drilling fees and a
five-year severance tax on production) as an
alternative to performance bonding.
Section VIII B, Miscellaneous
Recommendations. Financial assurances
and the concern about divestment were
appropriately addressed in the 2013
legislative passage of SB854, sponsored
by Senator Edwards, providing financial
assurance for gas and oil drilling.
Chapter 2 – Protecting Air Quality
UMCES-AL
MDE and DNR
2-A Require that operators in Maryland
establish a methane leak detection and repair
program that governs operations from wellhead to
Leak Detection is required in Section VI L,
Engineering, Design and Environmental
Controls and Standards, and operators will
F-4
the transmission line, regardless of whether
processing plants are necessary. All operators in
Maryland should voluntarily participate in
USEPA’s Natural Gas STAR program aimed at
implementing cost-effective strategies for reducing
methane emissions by the industry.
need to meet monitoring, reporting and
recordkeeping requirements as referenced
in Section VII, Monitoring, Recordkeeping
and Reporting.
No State action is necessary to allow
operators to voluntarily participate in
EPA’s Natural Gas STAR program.
Rather, MDE will require Top-down Best
Available Technology (BAT) to manage
air emissions as referenced in Section VI J,
Engineering, Design and Environmental
Controls and Standards
2-B
Encourage operators to either use newer
Section VI E and J, Engineering, Design
internal combustion engines or convert from diesel and Environmental Controls and Standards,
internal combustion engines to electric motors for
accepts this recommendation.
operating drilling rigs, pumps, and compressors
wherever possible by implementing “fleet average”
emission standards for NOx, VOCs, and PM2.5.
2-C
Require monitoring of hazardous air
pollutants at well pad sites.
Section VII, Monitoring, Recordkeeping
and Reporting, accepts this
recommendation.
2-D Monitor gamma and alpha radiation of
production brines.
Section VII, Monitoring, Recordkeeping
and Reporting, accepts this
recommendation.
2-E
Implement an air emissions monitoring
program throughout the region, focusing on
sources and fugitive sources of pollutants (and
pollutant precursors) at well pads and at other
sources resulting from natural gas production.
Section VII, Monitoring, Recordkeeping
and Reporting, accepts this
recommendation.
Chapter 3 – Well engineering and construction practices to ensure integrity and
isolation
UMCES-AL
MDE and DNR
3-A A best practice for anyone proposing to
operate in Maryland should be adoption of API’s
extensive guidelines for well planning—at least
those elements that are clearly relevant to onshore
development. Pre-permit site review should also be
required.
F-5
Section V, Plan For Each Well, accepts
this recommendation.
3-B
Site selection is a critical aspect of well
planning for multiple reasons discussed throughout
the report. As discussed in Chapter 1, we are
particularly concerned about drilling in areas where
there is a high probability of encountering large
underground voids (e.g., caverns, caves, mine
workings, abandoned wells, etc.) that have the
potential to cause a loss of fluid circulation during
drilling and impose additional risks during the
cementing process. Such hazards are locally
common in western Maryland and we recommend
that sites with a high probability of encountering
such hazards be avoided.
Section IV B, Location Restrictions and
Setbacks. The Departments generally
accept the proposed siting best practices
recommendation and note that certain
known hazards can be addressed through
modified drilling processes.
3-C
Surface casing must be fully cemented from
the bottom to the surface to provide total protection
of all USDW. There may be situations (e.g., very
deep wells) where fully cementing the intermediate
casing to the surface may not be required, however.
At a minimum, an absolute requirement should be
that all flow zones (including USDW) must be fully
protected through the use of cemented intermediate
well casings. Where this cannot be accomplished
feasibly with a single casing string, the use of
multiple casing strings should be favored in the well
design.
Section VI F, Engineering, Design and
Environmental Controls and Standards,
accepts this recommendation.
3-D Maryland should consider amending its
regulations to require SRCBL (or equivalent casing
integrity testing) and other types of logging ( i.e.,
neutron logging) as part of a cased-hole program.
Section VI F, Engineering, Design and
Environmental Controls and Standards,
accepts this recommendation.
3-E
Best practice would clearly call for use of
pressure testing of Marcellus shale gas wells in
Maryland, with specific criteria and technical details
governing the conduct of such tests likely
established through consultation with industry.
Maryland’s current regulations with regard to
pressure testing of cemented casings are even less
specific than those established by neighboring states
and appear to be in need of revision.
Section VI F, Engineering, Design and
Environmental Controls and Standards,
makes recommendations for mechanical
and pressure testing.
3-F
Use of BOPE with two or more redundant
Section VI G, Engineering, Design and
mechanisms should be considered a best practice for Environmental Controls and Standards,
MSGD in Maryland.
accepts this recommendation.
3-G We recommend that a sufficient number of
tiltmeter or micro-seismic surveys be performed as
part of any MSGD in Maryland, so that the extent,
F-6
Section VI H, Engineering, Design and
Environmental Controls and Standards,
and Section VII, Monitoring,
geometry, and location of Marcellus fracturing can
be adequately characterized across the entire region.
The principal goal of this effort would be to feed
useful information back to the operators, so that
subsequent hydraulic fracturing can be conducted
more safely and effectively. Data from such surveys
in Maryland (and other states) would also be
deemed crucial in evaluating whether HVHF might
eventually be safely conducted in locations where
the target formation is located within 2,000 ft of the
surface.
Recordkeeping and Reporting, accept this
recommendation.
3-H Maryland also has what appear to be
excellent regulations that are consistent with API
recommendation for plugging of wells. Given the
long expected time lags (of the order of 30 years)
between drilling and well decommissioning, the
biggest problem that we anticipate with plugging of
Marcellus wells in Maryland will be establishing
liability and ensuring that liable parties can be held
accountable for performing this critical task. The
costs associated with plugging wells that were
poorly constructed in the first place can be
extremely high, which reinforces the need to ensure
that any Marcellus shale gas wells in Maryland are
constructed to the highest standards.
The report makes many recommendations
for ensuring that any Marcellus shale gas
wells in Maryland are constructed to the
highest standards. In addition, financial
responsibility for closure was
appropriately addressed in the 2013
legislative passage of SB854, sponsored
by Senator Edwards (Section VIII B,
Miscellaneous Recommendations)
Chapter 4 – Protecting water resources
UMCES-AL
MDE and DNR
4-A A best practice for Maryland would be
establishment in regulation of 500 ft. and 2,000 ft.
setbacks (measured from the well pad, not from the
individual wellbores) for private wells and public
system intakes (both surface and ground water),
respectively.
Section IV A, Location Restrictions and
Setbacks. The Departments accept the
proposed 2,000 ft setback from public
wells, and note that current regulations
(COMAR 26.19.01.19G) already provide
a 1,000 ft setback from all drinking water
supplies, which includes private wells.
Additional considerations to setbacks
from private and public drinking water
systems are referenced in Section IV A,
Location Restrictions and Setbacks
4-B
We support Maryland Environmental Code
§ 14-110.1 (H.B. 1123) and recommend
predevelopment notification should be made to
public and private drinking water well owners.
Current Maryland regulations require that
the applicant identify all water wells
within 2,650 feet of the proposed well
location. The Department must mail
written notice of the decision to grant or
deny the permit to all landowners within
F-7
1,000 feet of the proposed well. Section
V, Plan for Each Well, adopts the
recommendation that notice be provided
to well owners within 2,500 feet and
extends it to all land owners within 2,500
feet.
4-C
Pre-drilling ground water testing should be
required to be conducted by the operator and the
results provided to MDE and to the well owner.
Post-drilling testing is often at the discretion of the
well owner, but a best management practice that
would enable improved understanding of the
potential for effects on ground water would be to
require postdrilling and completion testing by the
operator for all wells within a pre-determined
potentially affected region for a specified time
period after completion of well construction
activities.
Section VII, Monitoring, Recordkeeping
and Reporting accepts this
recommendation.
4-D Maryland might wish to consider ways of
strengthening its anti-degradation policy to take
account of the impacts of non-point source pollution
that are a major threat to its high quality waters.
One way that this might be accomplished would be
by revising the WQS rules to require that any land
development practices (e.g., forest management,
MSGD, etc.) conducted in Tier II watersheds meet
an anti-degradation standard.
Section IV B, Location Restrictions and
Setbacks, defers consideration of special
anti-degradation regulations for well
drilling until it undertakes revisions to
those regulations.
4-E
Maryland needs to carefully review its
stormwater regulations as they pertain to oil and gas
extraction; we recommend oil and gas extraction
sites be considered “hotspots.” Based on our review
of stormwater management practices in other states,
we recommend the use of both “active” and
“passive” stormwater management: (1) the
construction of properly bermed “zero-discharge”
pads that effectively collect all water on a pad site
and enable the reuse of this water during drilling
and completion operations; and (2) construction of a
below-grade lined pond adjacent to the bermed
zero-discharge pad that could be used as a sump
during active stormwater management phases and
easily converted into a retention pond prior to a
passive phase.
This recommendation is accepted with
modifications in Section VI A,
Engineering, Design and Environmental
Controls and Standards. Zero-discharge
from pads during drilling and completion
are adopted in Section VI A. The
collection of stormwater and other liquids
may cease only when all potential
pollutants have been removed from the
pad and appropriate, approved stormwater
management can be implemented.
4-F
Post-construction inspections of stormwater
structures should occur prior to well drilling and
Section VI A, Engineering, Design and
Environmental Controls and Standards.
F-8
completion.
Such inspections are routinely carried out
by the counties.
4-G There are very long gage records available
from USGS for most of the major western Maryland
rivers (Youghiogheny, Casselman, Savage,
Potomac, Georges Creek) that could possibly be
used to support MSGD; data for these and other
gaged systems can be used to inform a quantitative
analysis of acceptable water withdrawals for
MSGD. This analysis is much more difficult for
smaller streams and rivers due to data limitations,
although we believe that such an analysis should be
done. Our experience in Maryland watersheds as
well as review of other areas that have completed
such analysis, suggest that in western Maryland,
water withdrawals for proposed MSGD would need
to occur solely from the region’s large rivers (and
perhaps from one or more reservoirs). Small
streams (1) have significant existing withdrawals
for drinking water; (2) have small catchment areas
and discharges under most conditions; (3) are very
unlikely to have excess flow capacity for new
permitted withdrawals; and (4) can be readily
dewatered. Water may need to be temporarily stored
in centralized freshwater impoundments specifically
constructed for this purpose, but such
impoundments should never be allowed to receive
or store any wastewaters.
The State’s existing program for water
appropriation, which protects small
streams, is described in Section VI C,
Engineering, Design and Environmental
Controls and Standards. The
recommendation regarding storage of
water and wastewater are accepted in
Section VI A and C, Engineering, Design
and Environmental Controls and
Standards.
4-H To support preparations and training by first
responders and well pad staff for any chemical
emergencies, lists of chemicals to be used on site
(plus appropriate toxicological data, chemical
characterizations, MSDS, and spill clean-up
procedures) should be included in permit
applications.
These recommendations are accepted in
Section VI D and P, Engineering, Design
and Environmental Controls and
Standards.
4-I
Closed-loop drilling systems that sit within
secondary (and perhaps tertiary) containment are
preferable to open pit systems and should be
considered a best practice for Maryland.
Section VI A, Engineering, Design and
Environmental Controls and Standards,
adopts this recommendation.
4-J
Maryland should include a very strong
preference for on-site recycling of wastewaters in
permitting of shale gas development. Under no
circumstances should Maryland allow discharge of
untreated brine, partially-treated brine, or residuals
from brine treatment facilities, into the waters of the
These recommendations are accepted in
Section VI C and K, Engineering, Design
and Environmental Controls and
Standards.
F-9
state. Development of brine treatment plants that
recycle water to drillers should be discouraged in
favor of on-site treatment by mobile units and
immediate reuse as this decreases truck transport
and associated impacts.
4-K Maryland should review the relevant
regulations surrounding development and use of
underground injection wells for produced water
from shale gas development and, at the same time,
evaluate the capacity of nearby states to accept
produced water or residual brine from treatment of
produced water before permitting any development
in the state.
In Section VI K, Engineering, Design and
Environmental Controls and Standards,
the Departments recommend deferring
consideration of underground injection
wells because it is not likely that any will
be located in Maryland. As part of the
permit application, applicants will be
required to plan for the storage, treatment
and disposal of wastewater.
Chapter 5 – Protecting terrestrial habitat and wildlife
UMCES-AL
MDE and DNR
5-A Minimize well pad size, cluster multiple
well pads, and drill multiple wells from each pad to
minimize the overall extent of disturbance and
reduce fragmentation and associated edge effects.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
5-A.1 Concentrate operations including
roads on disturbed and open lands, ideally in
locations zoned for industrial activity and/or close
proximity to major roads.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
5-A.2 Adopt a no-net-loss of forest policy
requiring any activities that remove forest to be
offset by plantings elsewhere in the region.
Section IV B, Location Restrictions and
Setbacks. The Departments generally
accept the proposed siting best practices
recommendation and note that rules
regarding acreage determination and
temporary vs. permanent losses will need
to be developed.
5-A.3 Implement comprehensive planning
process to address the cumulative impact of
multiple projects, to channel development into
areas with greater amounts of existing disturbance,
and to avoid areas with intact forests (especially
forest interior habitat).
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
5-B
Allow for freshwater impoundments only.
Impoundments should not be used for flowback or
produced wastewater.
This recommendation is accepted in
Section VI A, Engineering, Design and
Environmental Controls and Standards.
5-B.1 Require watertight, closed metal
tanks with secondary containment for all storage of
This recommendation is accepted in
Section VI A and P, Engineering, Design
F-10
chemicals and wastewater.
and Environmental Controls and
Standards.
5-B.2 Include runoff and spill prevention,
response, and remediation plans as part of the
permitting process
This recommendation is accepted in
Section VI P, Engineering, Design and
Environmental Controls and Standards.
5-C
Establish and enforce setbacks to conserve
terrestrial and aquatic biodiversity.
Section IV A, Location Restrictions and
Setbacks. The Departments accept the
proposed location restrictions and setbacks
recommendation.
5-C.1 Enforce 300 ft minimum setbacks
from all floodplains, wetlands, seeps, vernal pools,
streams, or other surface water bodies.
Section IV A, Location Restrictions and
Setbacks. The Departments have expanded
this setback to 450 ft.
5-C.2 Exclude all development activities
from priority conservation areas (BioNet Tier I and
Tier II sites and wildlands). Enforce a 600 ft
setback from these areas.
Section IV A, Location Restrictions and
Setbacks. The Departments accept the
proposed location restrictions and setbacks
recommendation.
5-C.3 Enforce 1,000 ft setback from any
cave to reduce stress to bats and other obligate
subterranean species.
Section IV A, Location Restrictions and
Setbacks. The Departments accept the
proposed location restrictions and setbacks
recommendation.
5-D Review local noise ordinances to ensure
they are sufficiently protective. Artificial sound
barriers and mufflers should be considered where
natural noise attenuation would be inadequate,
especially in proximity to priority conservation
areas.
Section VI N, Engineering, Design and
Environmental Controls and Standards.
The Departments accept the proposed
siting best practices recommendation.
5-D.1 Avoid construction and drilling
operations during sensitive migratory and mating
seasons.
Section VI E, Engineering, Design and
Environmental Controls and Standards.
The Departments generally accept the
recommendation, noting that once drilling
and fracturing operations have been
initiated it is not safe to halt operations
except under an emergency.
5-E
Reduce the amount of light pollution at drill Section VI M. Engineering, Design and
pad sites by restricting night lighting to only when Environmental Controls and Standards,
necessary and to only the amount of lighting
accepts this recommendation.
required, direct light downward, instead of
horizontally, use fixtures that control light
directionality well, minimize glare, and use low
pressure sodium (LPS) light sources whenever
possible.
5-E.1 When drill pads are located within
F-11
Section VI M, Engineering, Design and
1,000ft of aquatic habitat, vegetative screens and
additional lighting restrictions could be required to
reduce light pollution into these sensitive areas.
Environmental Controls and Standards,
accepts this recommendation.
5-F
Co-locate linear infrastructure as
practicable with current roads, pipelines and power
lines to avoid new disturbance.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
5-F.1 Avoid stream crossings and any
disturbances to wetlands and riparian habitat.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
5-G Submit an invasive species plan as part of
permit application for preventing the introduction
of invasive species and controlling any invasive
that is introduced.
Section VI O, Engineering, Design and
Environmental Controls and Standards
accept this recommendation.
5-G.1 The invasive species management plan
should emphasize early detection and rapid
response and include baseline flora and fauna
inventory surveys of site prior to operations and
long-term monitoring plans for areas that could
become problematic after gas development occurs.
Section VI O, Engineering, Design and
Environmental Controls and Standards,
and Section VII, Monitoring,
Recordkeeping and Recording accept this
recommendation.
5-H Develop a two-phased reclamation strategy
comprised of (1) interim reclamation following
construction and drilling to reduce opportunities
for invasion and (2) postactivity restoration using
species native to the geographic range and seed
that is certified free of noxious weeds.
Section VI O and R, Engineering, Design
and Environmental Controls and
Standards, accepts this recommendation.
Chapter 6 – Protecting aquatic habitat, wildlife, and biodiversity
UMCES-AL
MDE and DNR
6-A Direct disturbance of any aquatic habitat for
shale gas development should not be permitted.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
6-B
A minimum 300 ft aquatic habitat setback
should be applied, with the distance measured from
the edge of any land disturbance, not from the
location of a particular wellbore, to the edge of a
particular habitat.
Section IV A, Location Restrictions and
Setbacks expands this recommended
setback to 450 ft.
6-C
Data that describe the biological resources
Section III, Comprehensive Gas
of western Maryland should be developed and made Development Plans (CGDP) adopts this
available to MSGD applicants. These data should be recommendation.
used to effectively channel development away from
high-value biological resources and into industrial
zones accessible via existing roads and highways.
F-12
6-D The use of multi-well pads to access
relatively large (~2 mi2) resources of shale gas
would enable the maintenance of reasonably low
levels of surface development.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
6-E
Cumulative surface development (including
all well pads, access roads, public roads, etc.) could
be maintained at less than 2 percent of the
watershed area in high-value watersheds.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation as a planning principle
for minimizing cumulative surface
impacts.
6-F
Initially, all MSGD could be excluded from
areas of high-value assets (e.g., BioNet sites,
stronghold watersheds, Tier II watersheds, etc.)
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation as a planning principle
for the applicant to consider when
determining the sequence of well pad
development.
6-G Closed drilling systems on zero-discharge
Sections VI A and E, Engineering Design
drilling pads on which all drilling and hydraulic
and Environmental Controls, accept this
fracturing fluids, chemicals, and liquid wastes are
recommendation.
collected and stored in steel tanks that provide
superior primary containment to holding ponds are a
best management practice. Vacuum trucks could be
used to handle on-site runoff during drilling and
well completion (see Chapter 4).
6-H Maryland should require an invasive species
management plan of industry prior to any drilling
operations. Such a plan should include, at the
minimum:
Section VI O, Engineering Design and
Environmental Controls, accepts this
recommendation.
6-H.1 A description of water sources to be used to
fill any impoundment, including analysis of any
invasive species that might be present at the
withdrawal site but absent from the watershed
where the impoundment will be located.
Section VI C and O, Engineering Design
and Environmental Controls accepts this
recommendation
6-H.2 Water withdrawal equipment should be
power-washed and rinsed with clean water before
leaving the withdrawal site.
Section VI C and O, Engineering Design
and Environmental Controls, accepts this
recommendation.
6-I
Maryland should prohibit the discharging of
any previously impounded water back into a natural
water body, thus reducing the chance for the
introduction of invasive species and short-term
elevated thermal regimes in streams.
Section VI O, Engineering Design and
Environmental Controls, accepts this
recommendation.
6-J
Wherever possible, existing roads should be
used in MSGD. Where new roads are required, PA
Section III, Comprehensive Gas
Development Plans (CGDP) and Section
VI A, Engineering Design and
F-13
DCNR recommendations could be adopted:
Environmental Controls, accept this
recommendation.
6-J.1 Use materials and designs (e.g.,
crowning, elimination of ditches, etc.) that
encourage sheet flow as the preferred drainage
method for any new construction or upgrade of
existing gravel roadways.
This recommendation is addressed in
Section VI A, Engineering Design and
Environmental Controls.
6-J.2 Where stream crossings are
unavoidable, use bridges or arched culverts to
minimize disturbance of streambeds.
Section IV B, Location Restrictions and
Setbacks. The Departments accept the
proposed siting best practices
recommendation.
6-J.3 Promote the use of geotextiles as a
way of reducing rutting and maintaining subbase
stability.
This recommendation is addressed in
Section VI A, Engineering Design and
Environmental Controls.
6-J.4 Open trenches within streams should
be avoided in favor of using directional boring
techniques.
Section IV B, Location Restrictions and
Setbacks. The Departments accept the
proposed siting best practices
recommendation and propose developing
siting policies to guide pipeline planning
and use of hydraulic directional drilling
practices.
6-K In general, during road and pad construction
a combination of BMPs should be used to reduce
sediment and erosion, recognizing that additional
protective measures might be necessary during wet
times of the year (primarily late winter and early
spring).
This recommendation is accepted in
Section VI A, Engineering Design and
Environmental Controls.
Chapter 7 – Protecting public safety
UMCES-AL
MDE and DNR
7-A The first line of defense in protecting public
safety is designing MSGD operations in a way that
maintains separation between MSGD infrastructure
(including transportation routes) and the public.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is also included in
Section VI B, Engineering Design and
Environmental Controls.
7-A.1 Facilities should be sited as far away Section III, Comprehensive Gas
as possible from homes, businesses, public
Development Plans (CGDP) adopts this
buildings, or places with high levels of recreational recommendation.
activity (e.g., hiking trails, parks, picnic areas, etc.)
(see Chapter 9 also).
7-A.2 Best management practices in well
construction (e.g., casing and cementing) should be
F-14
This recommendation is accepted in
Section VI F, Engineering Design and
followed to ensure wellbore integrity and isolation
(see Chapter 3).
Environmental Controls.
7-A.3 Proper monitoring and predevelopment assessment are important steps to
limit the migration of hydrocarbons, brines, or
hydraulic fracturing fluids into ground water,
causing pollution of underground drinking water
supplies and to enable rapid detection in the event
of migration (see Chapters 1 and 4).
Section VII, Monitoring, Recordkeeping
and Reporting accepts this
recommendation.
7-B
MSGD applicants should be required to
develop site-specific, emergency response plans
(ERP) that describes in detail how a particular
operator will respond to different emergencies that
may occur during each phase of shale gas
development at sites, or transportation routes
between sites, permitted for MSGD.
This recommendation is accepted in
Section VI P, Engineering Design and
Environmental Controls.
7-B.1 The ERP must include many types
of standard information, including the names and
contact information for first responders, and
location (including GPS coordinates) of MSGD
sites.
This recommendation is accepted in
Section VI P, Engineering Design and
Environmental Controls.
7-B.2 The ERP must include variations on
standard responses demonstrating sensitivity to
weather, time of day, time of year, and the
particular geography of sites (e.g., topographic and
soil conditions).
This recommendation is accepted in
Section VI P, Engineering Design and
Environmental Controls.
7-B.3 The ERP must also include a list of
all chemicals or additives used, expected wastes
generated by hydraulic fracturing, approximate
quantities of each material, the method of storage
on-site, MSDS for each substance, toxicological
data, and waste chemical properties.
This recommendation is accepted in
Section VI P, Engineering Design and
Environmental Controls.
7-C
Best management practices implemented to
avoid emergencies should include:
This recommendation is accepted in
Section VI Q, Engineering Design and
Environmental Controls.
7-C.1 Adequate perimeter fencing (at least This recommendation is accepted in
a 6 ft high chained link or equivalent), gates (with
Section VI Q, Engineering Design and
keyed locks), and signage in place around drill rigs, Environmental Controls.
engines, compressors, tanks, impoundments, and
separators, to restrict public access.
F-15
7-C.2 Use of safety or security guards to
further control access (particularly important
during active drilling and completion phases of an
operation).
This recommendation is accepted in
Section VI Q, Engineering Design and
Environmental Controls.
7-C.3 Duplicate keys to all locks should be This recommendation is accepted in
provided to the regulatory agency and to local
Section VI Q, Engineering Design and
emergency responders.
Environmental Controls.
7-D Maryland’s Department of Transportation
should calculate, evaluate, and address the major
impacts of additional truck traffic on the road and
highway system prior to the state permitting
MSGD.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is also included in
Section VI B, Engineering Design and
Environmental Controls.
7-D.1 Counties and municipalities should
also undertake an inventory and structural
evaluation of locally-owned bridges currently
exempt from federally mandated inspections to
ensure that these structures are capable of safely
handling the additional traffic (and loads)
associated with MSGD.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is also included in
Section VI B, Engineering Design and
Environmental Controls.
7-D.2 The state should establish a protocol
to allow for emergency transport of heavy or
oversized equipment during off-hour periods
(evenings, nights, and weekends).
Section VI B, Engineering Design and
Environmental Controls, indicates that the
State and Garrett County have existing
protocols, but it is unknown whether one
exists for Allegany County.
Chapter 8 – Protecting cultural, historical, and recreational resources
UMCES-AL
MDE and DNR
8-A Applicants for drilling permits should be
required to consult with Maryland Historical Trust
during the planning and permit application process
to identify all eligible or existing cultural or
historical sites in the vicinity of proposed MSGD
activity (including all drill pad sites, gas pipelines,
roads, and transportation routes to and from
MSGD facilities).
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
8-B
Regardless of whether or not a proposed
operation would be located on state or federal land,
best practice would require close consultation with
local governments, state park and forest officials,
national park managers, and wildlife managers
who are familiar with the resources that could be
impaired by shale gas development.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
8-C
Section IV B, Location Restrictions and
Applicants should be required to submit a
F-16
visual resource mitigation plan as part of the
permit application process based on site-specific
assessment ( i.e., viewshed analysis).
Setbacks. The Departments accept the
proposed siting best practices
recommendation, but note that a temporary
impact and a permanent impact will be
evaluated differently.
8-D Site selection for drilling pads in Maryland
should be locations that can provide natural
vegetative or topographic screening.
Section IV B, Location Restrictions and
Setbacks. The Departments accept the
proposed siting best practices
recommendation.
8-E
Siting of well pads, or the routing of
MSGD-related truck traffic, near high use
recreation areas should be avoided if possible.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is also included in
Section VI B, Engineering, Design and
Environmental Controls and Standards.
8-F
Maryland should impose a minimum 300 ft
setback from all cultural and historical sites, state
and federal parks, trails, wildlife management
areas, natural areas, wildlands, scenic and wild
rivers, and scenic byways to protect the region’s
most important cultural, historical, recreational,
and ecological resources. Setback considerations
should include high use areas, noise and visual
impacts, and public safety concerns.
Section IV A, Location Restrictions and
Setbacks. The Departments generally
accept the proposed location restrictions
and setbacks recommendation with the
following modifications. A 300 ft setback
may not adequate to protect the outdoor
recreational visitor’s experience. DNR will
develop new maps of public outdoor
recreational use areas to guide additional
recreational setbacks and mitigation
measures for minimizing public use
conflicts.
8-G The calculation of setback distances should
consider prevailing winds, topography, and
viewsheds, and repeatable formulas for calculating
setbacks should be established.
Section IV A, Location Restrictions and
Setbacks. The Departments generally
accept the proposed location restrictions
and setbacks recommendation. These
factors are also considered in Section VI
M, Engineering, Design and
Environmental Controls for lighting
management.
8-H Mitigative techniques, such as the use of
visual screens, sound barriers, camouflage, and
landscaping near cultural and historical sites, as
well as restricting the times of gas development
operations, should be required to minimize
disturbances and conflicts with recreational
activities in areas adjacent to gas development
zones.
Section IV B, Location Restrictions and
Setbacks. The Departments accept the
proposed siting best practices
recommendation. These factors are also
considered in Section VI M, Engineering,
Design and Environmental Controls for
lighting
8-I
Any permitted shale gas development
activities in the vicinity of public recreational
Section VI E, Engineering, Design and
Environmental Controls. The Departments
F-17
sites—including state forests—should be timed so
as to avoid periods of peak recreational activity
(e.g., holiday weekends, first day of trout season,
spring and fall hunting seasons, whitewater release
dates, etc.). Maryland DNR should collect and
provide data to help inform peak activity times.
generally accept the recommendation,
noting that once drilling and fracturing
operations have been initiated it is not safe
to halt operations except under an
emergency.
Chapter 9 – Protecting quality of life and aesthetic values
UMCES-AL
MDE and DNR
9-A Well-pad siting should consider the multiple Section III, Comprehensive Gas
factors that influence the quality of life and
Development Plans (CGDP) adopts this
aesthetics of rural life in western Maryland (e.g.,
recommendation.
location of existing infrastructure, traffic loads on
existing roads, etc.)
9-A.1 Site well pads away from occupied
buildings (e.g., dwellings, churches, businesses,
schools, hospitals, and recreational facilities)
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
9-A.2 Site well pads and associated
facilities in industrial parks (either new or existing)
designed and zoned for this type of industrial
activity
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
9-A.3 Site well pads in close proximity to
major interstate highways and exit ramps designed
to efficiently handle round-the-clock transportation
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
9-A.4 Reduce truck traffic associated with
water hauling through use of temporary pipelines
where possible.
Section VI B, Engineering, Design and
Environmental Controls, accepts this
recommendation.
9-B
Each of the counties in western Maryland
should revisit noise regulations and enforcement
policies and confirm they are appropriate for this
industrial activity.
Section VI N, Engineering, Design and
Environmental Controls addresses noise
regulations. No State action is necessary to
address this recommendation.
9-C No drilling or compressor stations should be
permitted within 1,000 ft of an occupied building.
Section IV A, Location Restrictions and
Setbacks accepts this recommendation.
9-D Require electric motors (in place of dieselpowered equipment) for any operations within
3,000 ft. of any occupied building
Noise is addressed in Section VI N,
Engineering, Design and Environmental
Controls and Standards.
9-D.1 Encourage electric motors in place
of diesel-powered equipment wherever possible.
This recommendation is accepted in
Section VI E, Engineering, Design and
Environmental Controls and Standards.
9-D.2 Restrict hours and times of operation VI E, Engineering, Design and
to avoid or minimize the greatest conflicts between Environmental Controls and Standards.
F-18
the public and MSGD.
The Departments generally accept the
recommendation, noting that once drilling
and fracturing operations have been
initiated it is not safe to halt operations
except under an emergency.
9-D.3 Require ambient noise level
determination prior to operations.
Noise is addressed in Section VI N,
Engineering, Design and Environmental
Controls and Standards. The Departments
do not see a need for ambient noise
measurements because the noise standards
apply to noise during operations.
9-D.4 Require construction of artificial
sound barriers where natural noise attenuation
would be inadequate.
This recommendation is accepted in
Section VI N, Engineering, Design and
Environmental Controls and Standards.
9-D.5 Equip all motors and engines with
appropriate mufflers.
Section VI N, Engineering, Design and
Environmental Controls and Standards,
requires that noise be controlled, by
mufflers if necessary.
9-E
All permit applicants should develop and
submit a detailed transportation plan for approval
by the regulatory authority prior to conducting any
site development, drilling, well work over, or well
completion activities
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is included in
Section VI B, Engineering, Design and
Environmental Controls and Standards.
9-E.1 The approval process for the
transportation plan should allow for adequate
comment by the public, state transportation
agencies, and county roads departments.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation and is included in section
VI B, Engineering, Design and
Environmental Controls and Standards.
9-F
It is recommended that new road
construction follows PADCNR guidelines for
construction of permanent non-paved roads to
address potential environmental impacts, offset
erosion, and avoid damage to environmentally
sensitive areas.
This recommendation is addressed in
Section VI, A, Engineering, Design and
Environmental Controls and Standards.
9-G We recommend the use of viewshed
analysis to help determine the best location for
MSGD-related infrastructure as well as to
determine what mitigative techniques would be
appropriate.
This recommendation is accepted in
Section III, Comprehensive Gas
Development Plans (CGDP) and Section
IV B, Location Restrictions and Setbacks.
9-H We recommend use of mitigative techniques This recommendation is accepted in
(e.g., the use of visual screens, camouflages, paint
Section IV B, Location Restrictions and
schemes, evergreen buffers, and landscaping
Setbacks.
techniques) to minimize degradation of western
F-19
Maryland viewsheds by MSGD.
Chapter 10 – Protecting agriculture and grazing
UMES-AL
MDE and DNR
10-A Soil conditions at sites being considered for This recommendation is accepted in
shale gas development should be evaluated as part Section IV B, Location Restrictions and
of the planning process.
Setbacks.
10-B Prime agricultural soils and prime farmland
protected by Maryland’s existing land easement
programs should not be disturbed for well pad
siting, road construction, or any ancillary gas
development activities.
This recommendation is accepted in
Section III, Comprehensive Gas
Development Plans (CGDP).
10-C Highly erodible soils should also be
identified as part of the planning process and
appropriate best practices employed to prevent
erosion and sedimentation problems in developing
these areas (see Chapter 4).
This recommendation is accepted in
Section IV B, Location Restrictions and
Setbacks.
10-D Well pads, infrastructure, roads, and utility
corridors should generally be sited along field
edges, thus avoiding bisection of fields.
This recommendation is accepted in
Section IV B, Location Restrictions and
Setbacks.
10-E Topsoil should be stockpiled during site
development activities, covered during storage,
redistributed back onto agricultural land as part of
the land reclamation process, and soil compaction
should be avoided at all times.
This recommendation is accepted in
Section VI R, Engineering, Design and
Environmental Controls and Standards.
10-F Operators must fence livestock out of gas
development areas.
This recommendation is accepted in
Section VI Q, Engineering, Design and
Environmental Controls and Standards.
F-20
APPENDIX G – JUSTIFICATION FOR EXPANSION OF THE AQUATIC HABITAT
SETBACK FROM 300 FT TO 450 FT
Maryland’s Proposed Setback (Minimum Riparian Buffer) Recommendations for
Gas Development Infrastructure Associated with Aquatic Habitats in Western
Maryland
Prepared by: Tony Prochaska and Ronald Klauda
Maryland Department of Natural Resources
January 30, 2014
Riparian buffers are among the most diverse and functionally-important landscape
features because of their unique position as an interface (ecotone) between aquatic and
terrestrial habitats. Intact riparian buffers are vital components of watersheds and provide
important ecological services. Buffers serve to protect surface and ground water quality
from impacts associated with human land uses. Buffers provide food and habitat for an
array of plants and animals (i.e., they support high biodiversity) and, if wide enough,
provide corridors essential for terrestrial wildlife movements and breeding areas for
forest interior-dwelling birds. Although riparian buffers comprise a small percentage of a
watershed area, they often harbor a disproportionately high number of plants and animals.
Riparian buffers along headwater (1st, 2nd, and 3rd order) streams have much more
influence on overall water quality than buffers occurring downstream along larger
streams and rivers.
The final UMCES-AL Report titled “Recommended Best Management Practices for
Marcellus Shale Gas Development in Maryland” authored by Keith Eshleman and
Andrew Elmore recommends a minimum setback (buffer width) of 300 ft for well pad
locations from all aquatic habitats, including streams, rivers, seeps, springs, vernal pools,
wetlands, lakes, ponds, reservoirs, floodplains and other surface water bodies (Table 1-1:
page 1-12). This minimum setback is measured from the limit of disturbance (not the
wellbore) to the edge (high water mark or landward edge of an active floodplain) of the
specific aquatic habitat present.
The UMCES-AL recommendation of a minimum setback of 300 ft in their report was
based, in large part, on actual practices being employed by neighboring states where
Marcellus shale gas development is underway. The UMCES-AL Report authors wanted
to be reasonably consistent with the best setback practices in other states. Although the
Maryland Department of the Environment (MDE) and the Maryland Department of
Natural Resources (DNR) recognize that the proposed aquatic setback recommendation
outlined in the UMCES-AL Report (Table 1-1, page 1-12) would provide some level of
protection for water quality and biological diversity, we feel that this setback
recommendation should be increased to better reflect the level of protection the
Departments must ensure for our environment and natural resources. Furthermore, the
H-1
Departments determined that it is necessary to make the following modifications and
additions: 1) Prohibit the development of well pads on land with a slope > 15 percent
(this was recommended in the UMCES-AL final report, but not listed as a key
recommendation), 2) Expand the drill pad location restrictions and setbacks for aquatic
habitats listed in Table 1-1 to include all natural gas development that results in surface
alterations (including permanent roads, compressor stations, and other needed
infrastructure), and 3) Recommend riparian buffer expansion (i.e., setbacks) to 450 ft to
increase water quality and biodiversity protection.
As explained in more detail below, a 450 ft setback will provide significant water quality
protection, as would the 300 ft setback recommended in the UMCES-AL Report. But, in
addition, a minimum setback of 450 ft will provide a higher level of protection for
biodiversity (with a focus on aquatic biodiversity), ensure sufficient corridor width
needed for terrestrial wildlife movement and forest interior-dwelling bird species, and
reduce the visual, noise, and light impacts of gas extraction operations in close proximity
to aquatic habitats.
The Departments’ recommended minimum setback distance from aquatic habitats of 450
ft is supported by several studies on buffer or life zone requirements for reptiles and
amphibians. Semlitsch and Bodie (2003) summarized data from the scientific literature
on the use of terrestrial habitats by amphibians and reptiles associated with pond and
stream habitats, both permanent and temporary, in the United States and Canada. From
these data, they calculated mean minimum and mean maximum core terrestrial habitat
distances measured from the outer edge of aquatic areas; i.e., essentially riparian buffer
widths. Mean minimum distances were 127 m (417 ft) for 33 reptile species and 159 m
(522 ft) for 32 amphibian species. The mean minimum distance from aquatic areas for all
herpetofauna (65 amphibian and reptile species) was 142 m (466 ft). By comparison,
mean maximum distances (buffer widths) were 289 m (948 ft) for reptiles and 290 m
(951 ft) for amphibians. Mean maximum distances for all herpetofauna was 289 m (948
ft). The Semlitsch and Bodie (2003) paper can be found here:
http://www.mctga.org/Stream%20Buffer%20Information/Semlitsch%20and%20Bodie%
202003.pdf. In another paper, Calhoun and deMaynadier (2007) reported even longer
mean and maximum life zone distances (buffer widths) from aquatic areas: for marbled
salamanders (368 and 1476 ft, respectively), spotted salamanders (390 and 817 ft),
Jefferson salamanders (476 and 2051 ft), and wood frogs (633 and 1549 ft). Harper et al.
2008 indicated that a minimum terrestrial core habitat radius of 100 to 165 m (328 to 541
ft) is necessary to maintain populations of spotted salamanders (95 percent probability
and persistence of 20 years). The four amphibian species referenced above are present in
western Maryland (including Garrett and Allegany Counties). The Jefferson salamander
has a State rank of S3 (i.e., Watchlist), meaning that is considered rare to uncommon in
Maryland.
On June 6, 2011, Governor Martin O’Malley signed Executive Order 01.01.2011.1146
establishing the Marcellus Shale Safe Drilling Initiative. This Executive Order called for
additional studies to ensure that Maryland had sufficient information upon which to base
46
www.governor.maryland.gov/executiveorders/01.01.2011.11.pdf
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a decision to allow or not allow unconventional gas development in western Maryland. In
his Executive Order, protection of the State’s abundant natural resources was critical. In
the spirit of this directive, the Departments recommend a minimum setback for gas
development infrastructure associated with aquatic habitats in western Maryland of 450
ft. This buffer width is similar to the mean minimum width of 466 ft for 65 herpetofauna
species recommended by Semlitsch and Bodie (2003). Although a minimum setback even
greater than 450 ft is supported by scientific studies, the Departments feel that this
setback, if strictly enforced, should be sufficiently protective of water quality and
biodiversity, and still provide for ample amounts of land surface for infrastructure
necessary for Marcellus Shale natural gas development (if/when it is permitted in
Maryland).
References
Calhoun, A. J. K. and P. K. deMaynadier (eds.). 2007. Science and Conservation of
Vernal Pools in Northeastern North America. CRC Press, Boca Raton, FL, USA.
Calhoun, A.J.K. and M.W. Klemens. 2002. Best development practices: Conserving
pool-breeding amphibians in residential and commercial developments in the
northeastern United States. MCA Technical Paper No. 5, Metropolitan Conservation
Alliance, Wildlife Conservation Society, Bronx, New York.
Harper, E.B., T.A. Rittenhouse and R.D. Semlitsch. 2008. Demographic consequences of
terrestrial habitat loss for pool-breeding amphibians: predicting extinction risks
associated with inadequate size of buffer zones. Conservation Biology 22(5):1205-1215.
Johnson, Craig W. Buffler, Susan. 2008. Riparian buffer design guidelines for water
quality and wildlife habitat functions on agricultural landscapes in the Intermountain
West. Gen. Tech. Rep. RMRS-GTR-203. Fort Collins, CO: U.S. Department of
Agriculture, Forest Service, Rocky Mountain Research Station. 53 p.
Rittenhouse, T.A. and R. D. Semlitsch. 2007. Distribution of amphibians in terrestrial
habitat surrounding wetlands. Wetlands 27(1):153-161
Semlitsch, R.D. and R. Bodie. 2003. Biological criteria for buffer zones around wetlands
and riparian habitats for amphibians and reptiles. Conservation Biology 17(5):1201-1228.
Semlitsch, R.D. 1998. Biological delineation of terrestrial buffer zones for pond-breeding
salamanders. Conservation Biology 12:1113-1119.
U.S. Department of Agriculture, Natural Resources Conservation Service "National
Engineering Handbook, Part 630, Chapter 7" (2009)
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APPENDIX H – ACRONYMS
AAPG
AMD
AOR
API
ASTM
BACI
BAT
BMP
BP
CAS
CBL
CFR
CGDP
CO2e
COMAR
CPCN
CSSD
dBA
DNA
DNR
DOE
EA
EIS
EPA
FAQ
Fed. Reg.
FERC
ft
g/bhp-hr
GAO
GHG
GIS
gpd
GPS
HB
HCS
HVHF
IBA
IPCC
LDAR
LFN
LOD
m
American Association of Petroleum Geologists
Acid mine drainage
Area of Review
American Petroleum Institute
American Society for Testing and Materials
Before, after, control, impact
Best Available Technology
Best Management Practice
Best Practices
Chemical Abstract Service
Cement bond logging
Code of Federal Regulations
Comprehensive Gas Development Plan
Carbon Dioxide Equivalents
Code of Maryland Regulations
Certificate of Public Convenience and Necessity
Coalition for Sustainable Shale Development
A-weighted decibels
Deoxyribonucleic Acid
Maryland Department of Natural Resources
Department of Energy (US)
Environmental Assessment
Environmental Impact Statement
Environmental Protection Agency (US)
Frequently Asked Questions
Federal Register
Federal Energy Regulatory Commission
Feet
grams per brake horsepower per hour
Government Accountability Office (US)
Greenhouse Gas
Geographic Information System
Gallons per day
Global Positioning System
House Bill
Hazard Communication Standard
High volume hydraulic fracturing
Important Bird Area
Intergovernmental Panel on Climate Change
Leak Detection And Repair
Low frequency noise
Limit of Disturbance
Meter
H-1
MALPF
MDA
MDE
MET
MGS
MMcfd
MSAC
MSGD
NEA
NEPA
NESHAP
NETL
NORM
NPDES
NRMA
NSPS
OPS
OSHA
PAH
PHMSA
PNAS
POTW
ppm
PSC
PWS
QA/QC
RCRA
SB
SDS
SDWA
SOPA
SPCC
SRBC
SRCBL
STAC
SWPA
TCLP
TDS
TEG
TENORM
TMDL
TSS
UIC
UK
Maryland Agricultural Land Preservation Foundation
Maryland Department of Agriculture
Maryland Department of the Environment
Maryland Environmental Trust
Maryland Geological Survey
Million cubic feet per day
Marcellus Shale Advisory Commission
Marcellus Shale Gas Development
Natural Environment Area
National Environmental Policy Act
National Emission Standards for Hazardous Air Pollutants
National Energy Technology Laboratory
Naturally occurring radioactive material
National Pollutant Discharge Elimination System
Natural Resources Management Area
New Source Performance Standard
Office of Pipeline Safety
Occupational Safety and Health Administration (US)
Polycyclic aromatic hydrocarbon
Pipeline and Hazardous Materials Safety Administration (US)
Proceedings of the National Academy of Sciences
Publicly owned treatment works
Parts per million
Public Service Commission (MD)
Public Water System
Quality Assurance/Quality Control
Resource Conservation and Recovery Act
Senate Bill
Safety Data Sheets
Safe Drinking Water Act
Surface Owners Protection Act
Spill Prevention Control and Countermeasure
Susquehanna River Basin Commission
Segmented radial cement bond logging
Scientific and Technical Advisory Commission (Chesapeake Bay
Program)
Source Water Protection Area
Toxicity Characteristic – Leaching Procedure
Total dissolved solids
Tri-ethylene glycol
Technologically enhanced naturally occurring radioactive material
Total Maximum Daily Load
Total suspended solids
Underground Injection Control
United Kingdom
H-2
UMCESAL
USC
USDA
USGS
VAD
VOC
WIP
WWTP
University of Maryland Center for Environmental Science – Appalachian
Laboratory
United State Code
United States Department of Agriculture
United States Geological Survey
Vibroacoustic disease
Volatile organic compound
Watershed Implementation Plan
Wastewater treatment Plant
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