MARCELLUS SHALE SAFE DRILLING INITIATIVE STUDY PART II

MARCELLUS SHALE SAFE DRILLING INITIATIVE STUDY PART II
Draft for Public Comment
MARCELLUS SHALE SAFE DRILLING
INITIATIVE STUDY
PART II
BEST PRACTICES
AUGUST 2013
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
Draft for Public Comment
Draft for Public Comment
MARCELLUS SHALE SAFE DRILLING
INITIATIVE STUDY
PART II
BEST PRACTICES
AUGUST 2013
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
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Draft for Public Comment
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Draft for Public Comment
EXECUTIVE SUMMARY ..................................................................................... v
SECTION I – ORGANIZATION OF THE REPORT............................................. 1
SECTION II – OVERVIEW.................................................................................... 3
A.
B.
C.
D.
MARCELLUS SHALE ........................................................................................... 3
DEVELOPMENTS IN MARYLAND .................................................................... 3
THE EXECUTIVE ORDER AND THE ADVISORY COMMISSION................. 4
THE WORK OF THE ADVISORY COMMISSION ............................................. 5
SECTION III – COMPREHENSIVE GAS DEVELOPMENT PLANS................. 8
A.
B.
C.
D.
E.
APPLICATION CRITERIA AND SCOPE ............................................................ 9
PLANNING PRINCIPLES ..................................................................................... 9
PROCEDURE AND APPROVAL PROCESS ..................................................... 10
BENEFITS OF A COMPREHENSIVE GAS DEVELOPMENT PLAN ............. 11
THE SHALE GAS DEVELOPMENT TOOLBOX .............................................. 11
SECTION IV – LOCATION RESTRICTIONS AND SETBACKS..................... 14
A. LOCATION RESTRICTIONS AND SETBACKS .............................................. 14
B. SITING BEST PRACTICES................................................................................. 19
SECTION V – PLAN FOR EACH WELL............................................................ 20
SECTION VI – ENGINEERING, DESIGN AND ENVIRONMENTAL
CONTROLS AND STANDARDS........................................................................ 22
A. SITE CONSTRUCTION AND SEDIMENT AND EROSION CONTROL ........ 22
1.
The pad......................................................................................................... 22
2.
Tanks and containers.................................................................................... 23
3.
Pits and Ponds .............................................................................................. 23
4.
Pipelines....................................................................................................... 23
5.
Road Construction ....................................................................................... 24
6.
Ancillary equipment..................................................................................... 25
B. TRANSPORTATION PLANNING ...................................................................... 25
C. WATER ................................................................................................................. 26
1.
Storage ......................................................................................................... 26
2.
Water withdrawal......................................................................................... 26
3.
Water reuse .................................................................................................. 28
D. CHEMICAL DISCLOSURE................................................................................. 28
E. DRILLING ............................................................................................................ 29
1.
Use of electricity from the grid.................................................................... 29
2.
Initiation of drilling...................................................................................... 29
3.
Pilot hole ...................................................................................................... 30
4.
Drilling fluids and cuttings .......................................................................... 30
5.
Open hole logging........................................................................................ 31
F. CASING AND CEMENT ..................................................................................... 32
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G.
H.
I.
J.
K.
L.
M.
N.
O.
P.
Q.
R.
1.
Requirements for casing and cement ........................................................... 32
2.
Isolation........................................................................................................ 33
3. Cased-hole logging, Integrity testing and Pressure testing.......................... 33
BLOWOUT PREVENTION ................................................................................. 33
HYDRAULIC FRACTURING ............................................................................. 34
FLOWBACK AND PRODUCED WATER ......................................................... 34
AIR EMISSIONS .................................................................................................. 34
1.
Green Completion or Reduced Emissions Completion ............................... 35
2.
Flaring .......................................................................................................... 35
3.
Electricity from the grid............................................................................... 35
4.
Engines......................................................................................................... 35
5.
Storage tanks................................................................................................ 36
6.
Natural Gas Star........................................................................................... 36
WASTE AND WASTEWATER TREATMENT AND DISPOSAL.................... 36
LEAK DETECTION ............................................................................................. 38
LIGHT ................................................................................................................... 38
NOISE ................................................................................................................... 39
INVASIVE SPECIES............................................................................................ 40
SPILL PREVENTION, CONTROL AND COUNTERMEASURES AND
EMERGENCY RESPONSE ................................................................................. 41
SITE SECURITY .................................................................................................. 42
CLOSURE AND RECLAMATION BOTH INTERIM AND FINAL ................. 42
SECTION VII – MONITORING, RECORDKEEPING AND REPORTING...... 44
SECTION VIII – MISCELLANEOUS RECOMMENDATIONS........................ 46
A. ZONING ................................................................................................................ 46
B. FINANCIAL ASSURANCE................................................................................. 46
C. FORCED POOLING ............................................................................................. 46
SECTION IX – MODIFICATIONS TO PERMITTING PROCEDURES ........... 47
SECTION X – IMPLEMENTING THE RECOMMENDATIONS...................... 48
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
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
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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. The schedule was
extended by one year for the second report, which is 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 was made available for public comment on June 25,
2013. After consideration of the comments, the Departments submit this report on Part II
of the study, Best Practices. The Departments’ Best Practices recommendations are very
similar to those in the UMCES-AL report. Where a UMCES-AL recommendation was
rejected or modified, an explanation is provided.
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
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
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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. 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.
.
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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 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 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.
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
Draft for Public Comment
Maryland, the UMCES-AL report, and a comparison of the UMCES-AL
recommendations with those of the Departments.
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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, 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.
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.
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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. 1 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. 2 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 three-part study and reporting findings and
recommendations. The Commission is staffed by DNR and MDE. The completed study
will 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 Statelevel severance tax, and the desirability of legislation to establish standards of
liability for damages caused by gas exploration and production;
1
Additional applications were received in 2011. Applications for a total of seven wells were received by
MDE, but all have been withdrawn. In general, drilling has migrated to areas where not only natural gas,
but also natural gas liquids that are more valuable, can be produced from formations.
2
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 also apply to other formations and techniques.
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(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.
Part I of the study 3 , 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. The schedule was
extended by one year for the second report.
D. The Work of the Advisory Commission
The Governor announced the membership of the Advisory Commission in July, 2011,
and the Commission has met 18 times through June 10, 2013. Most meetings were in
Allegany or Garrett Counties, but two were held in Hagerstown and two in Annapolis.
The Departments have provided written information and briefings to the Advisory
Commission on issues relating to HVHF. Speakers representing scientific organizations,
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 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 region 4 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
indirectly, by drill pads, pipeline/road construction and use. The findings, Marcellus
3
http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Meetings/
Marcellus_Shale_Report_Part_I_Dec_2011.pdf
4
http://www.dnr.state.md.us/streams/marcellus.asp
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Shale Gas Development in Maryland: A Natural Resource Analysis, 5 were presented to
the Commission on February 27, 2012.
MDE funded the Maryland Geological Survey to perform a limited study of methane
levels in drinking water wells in Garrett County. Approximately 50 wells were sampled
and a report, Dissolved-Methane Concentrations in Well Water in the Appalachian
Plateau Physiographic Province of Maryland, was issued on November 1, 2012.
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 2013 session of the General Assembly, three bills were introduced based on the
recommendations of the Commission: Business Occupations – Oil and Gas Land
Professionals (SB766, HB828); Environment – Gas and Oil Drilling – Financial
Assurance (SB854); and Natural Gas Severance Tax and Impact Account (SB879). Of
these, the first two passed. 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. Senator George
Edwards, a member of the Commission, sponsored all three bills.
At the same time, the Governor proposed and the legislature approved a supplemental
Fiscal Year 2013 appropriation that provides 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
Management Practices for Marcellus Shale Development in Maryland 6 (the UMCES-AL
Report), was made available to the Commission and the public in February 2013 and is
included as Appendix F. The Departments also charted a comparison of the
recommendations of UMCES-AL and the Departments; it is included in Appendix F.
5
http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/
Eshleman_Elmore_Final_BMP_Report_22113_Red.pdf
6
http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/
Meetings/MAC_NaturalResourcesAnalysis.pdf
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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.
For the draft report
This document is the Departments’ draft of the report on recommended best practices.
The draft will be open for public comment for 30 days, after which the Departments will
consider the comments and issue a final report on recommended best practices in August
2013. This draft report contains the Departments’ recommendations. Following a public
comment period, the report will be issued in final form.
For the final report
A draft was made available for public comment on June 25, 2013. 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 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.
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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 specific permit to drill a well. 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. We propose that
Maryland require, as a prerequisite to the issuance of any permit to drill a gas
exploration 7 , extension, or production well, that the prospective applicant first submit a
Comprehensive Gas Development Plan (CGDP). A CGDP should be required even for
exploration and extension wells, because of the likelihood that an exploration well will
become a production well. The siting of the exploration well therefore is potentially as
important as the siting of a production well. 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
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
7
Current Maryland law allows an applicant to apply for a permit for an exploratory well; however,
production may not commence until the environmental assessment has been completed and approved by
MDE and MDE has issued a permit for production. Md. Env. Code 14-106. Thus, a permit for an
exploratory well does not guarantee that a production permit will be granted. If the CGDP were to exclude
exploratory wells, minimum setbacks and other siting restrictions would still apply, but the opportunity for
larger, landscape-level planning would be compromised. For this reason, the Departments recommend that
a CGDP be required even for an exploratory well
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conflicts and addressing the concerns associated with maintaining the rural character of
western Maryland, and protecting high value natural resources and resource-based
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 well permits
would be issued. The associated recommendations, 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 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.
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.
B. Planning principles
1.
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.
Avoid, minimize and mitigate impact on resources as discussed in Section IV.
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% 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.
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9.
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.
10.
Additional planning elements include
a)
Identification of travel routes.
b)
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.
c)
Consistency with local zoning ordinances and comprehensive planning
elements.
d)
Identification of all federal, state and local permits needed for the activities.
C. Procedure and Approval Process
1.
An applicant with the right to extract natural gas prepares a preliminary CGDP
that best avoids and then minimizes harm to 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 wells, well pads, gathering and transmission lines, compressor
stations, separator facilities, access roads, and other supporting infrastructure.
3.
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.
4.
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.
5.
The public review and approval process will be initiated upon request of the
applicant following receipt of agency comments.
6.
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.
7.
The plan is presented at a public meeting by the applicant and the public shall be
allowed to comment on the plan.
8.
The applicant may further modify the plan based on alternatives analyses and
public comment before submitting it to the State for approval.
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9.
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.
10.
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.
11.
Once the CGDP is approved, the entity may file a permit application for one or
more wells that are consistent with the plan.
12.
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.
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:
1.
Better protection of natural, social, cultural, recreational and other resources, and
reduced cumulative impact.
2.
Fast track wetland and waterway permit approvals for multiple individual
impacts, such as those associated with pipeline networks and road construction,
contingent on 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.
Expedited consideration 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.
7.
Reduced expense and risk associated with leveraging existing infrastructure and
centralizing various processing needs.
8.
Reduced public use conflict and improved public good will.
E. The Shale Gas Development Toolbox
The toolbox will provide access to geospatial planning data necessary to address the
Comprehensive Gas Development Plan (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
11
Draft for Public Comment
tool 8 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 right of ways for gas lines and transmission inks
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.
a. Streams, rivers and flood plains – stream maps will include designated use
classifications
b. Wetlands
c. Reservoirs
d. Irreplaceable Natural Areas (BioNet Tier 1 and 2 areas)
e. Cultural and historic areas, including National Registry sites
f. Local, state and federal parks, including setback recommended through
participatory GIS workshops
g. Wild and scenic rivers
h. Scenic byways
i. Mapped limestone outcrops and known caves
j. Historic gas wells
k. Private and public groundwater wells or surface water intakes
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 %
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.
8
http://dnrweb.dnr.state.md.us/merlin/
12
Draft for Public Comment
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. Mapped underground coal mines
i. Aerial imagery – useful for evaluating actual ground conditions
4. Planning element: Identification of appropriate natural resource mitigation actions to
address unavoidable impacts.
a. The Watershed Resources Registry Tool 9 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.
9
watershedresourcesregistry.com
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Section IV – Location Restrictions and Setbacks
This section addresses restrictions on the locations of well pads, 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 “off limit”, 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 these
will be continued. 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
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
2,000
Gas
Well
Existing gas well in
the same reservoir
COMAR
26.19.01.09 E
1320
Oil
Well
Exiting oil well in
the same reservoir
Unless the Department is
provided with geologic
evidence of reservoir
separation to warrant
granting an exception
Unless the Department is
provided with geologic
evidence of reservoir
separation to warrant
granting an exception
14
COMAR
26.19.01.09 F
Draft for Public Comment
1,000
Well
A school, church,
drinking water
supply, wellhead
protection area, or
an occupied
dwelling
Unless written
COMAR
permission of the owners 26.19.01.09 G
is submitted with the
application and approved
by the Department
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. Under a
scenario that excluded drilling from the Accident gas storage dome and assumed an 8,000
foot horizontal drill length, approximately 98 % 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 94 % 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’ comments, are provided in Table I-2
below.
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Draft for Public Comment
Table I-2: Setback Recommendations from UMCES-AL Report with Adjustments
Recommended by the Departments
Distance
(feet)
From
To
300 10
Aquatic habitat (defined
as all streams, rivers,
seeps, springs, wetlands,
lakes, ponds, reservoirs,
and 100 year
floodplains)
Edge of drill
pad
disturbance
Agree
600
Special conservation
areas (e.g., irreplaceable
natural areas, wildlands)
Edge of drill
pad
disturbance
Agree; may be expanded on a
case by case basis, after DNR
conducts a participatory GIS
workshop; 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
500 feet on the downdip side
1,000
Mapped underground
coal mines
Borehole
Unnecessarily restrictive;
alternative approach
recommended; see Section VID
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
Agree
10
MDE and DNR Adjustment
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.
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Draft for Public Comment
500
2,000
Private groundwater
wells
Borehole
Expand to 1,000 feet, as
required by current regulations.
Public groundwater
wells or surface water
intakes
Borehole
Agree; drinking water
reservoirs must also be
protected
The Departments generally accept the proposed location restrictions and setbacks with
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%.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.
Modify restrictions for setbacks from limestone outcrops to the borehole; setback
areas for mapped limestone outcrops apply only to 500 feet on the downdip side of the
formation.
There is no need to adhere to
setbacks on the updip side because
downdip side
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 20 degrees, while the beds in Allegany County
dip at steeper angles. Using a 200 foot depth for potential karst development as a
conservative estimate, a 500 foot setback on the downdip side of the limestone outcrop
would be sufficiently protective.
4.
Setbacks for known and discovered caves should remain at 1000 feet because of
the biological resource sensitivity and the potential for groundwater contamination.
5.
Modify restrictions for setbacks from mapped underground coal mines to the
borehole. 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
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Draft for Public Comment
involves careful site evaluation and pilot hole investigations. See Section VI-D for a
description on pre-drill planning.
6.
Replace the recommended 500 foot setback from private groundwater wells to the
borehole with a 1,000 foot setback.
Current regulations, COMAR 26.19.01.19G, are more protective and state that an oil and
gas well cannot be closer than 1,000 feet to a drinking water supply. Private groundwater
wells are considered a drinking water supply.
7.
The setback requirement of 2,000 feet shall apply upstream of any surface water
intake on a flowing stream, as a radius around any drinking water well, and from the edge
of any drinking water reservoir.
8.
Expand 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 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.
9.
DNR will develop new maps of public outdoor recreational use areas to establish
additional recreational setbacks and mitigation measures for minimizing public use
conflicts. DNR will initiate the first of a series of participatory GIS workshops to develop
these new maps in the fall of 2013, focusing on the recreational amenities of Savage
River State Forest. The results of this workshop will be weighed against the alternative
option of expanding the setback to 600 feet.
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. 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. 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. DNR will launch a formal process for developing new maps of use areas that
would include participatory GIS workshops conducted with facility managers, friends
groups, frequent visitors, and other stakeholders. The maps generated from these
discussions and workshops could then be used to inform comprehensive gas development
plans, setback considerations, mitigation measures and timing of shale gas development
activities. This recommendation could be incorporated as an element of the public
comment period of a CGDP process, or be developed independently of the CGDP and
included in the Shale Gas Development Toolbox.
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10.
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-D.
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.
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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 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. 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. Addressing lost circulation
10. Casing
11. Cementing
12. Drilling fluids
13. Wellbore hydraulics
14. Barrier design
15. Integrity and pressure testing
16. Blow out protection
17. Contingency planning
18. Communications plan, including communication with contractors and
subcontractors
19. Site security
20
Draft for Public Comment
20. Storage, treatment and disposal of water, wastewater, fuel and chemicals
21. Road construction and transportation planning
22. Spill prevention, control and countermeasures, and emergency response
23. Invasive species
24. Waste handling, treatment and disposal
25. Monitoring the well during production to detect well problems and failure of
casing or cement
26. Reclamation
Consistent with UMCES-AL recommendation 4-B, the applicant will be required to
notify the owners of any drinking water well 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.
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Draft for Public Comment
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 conditions 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 are nearly silent on design and
construction requirements, except for pits and tanks. 11 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. 12 As these plans are written
to address the requirements of shale gas development, training of plan review and
approval staff 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,
and mixing and pumping the cement. Pollutants released 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
permeability 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
by an impermeable berm such that the pad can contain at least the volume of 2.7 inches
of rainfall within a 24 hour period. The berm may be made impermeable by extension of
the liner. 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
11
12
COMAR 26.19.01.10 J through K.
COMAR 26.19.01.06C (12) and (13).
22
Draft for Public Comment
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, 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
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
23
Draft for Public Comment
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, which
should be addressed by the PSC.
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.
5.
Road Construction
The UMCES-AL report makes several recommendations about roads. Wherever possible,
existing roads should be used. Where new 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,
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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. 13 The Bureau of Forestry works closely with
The Pennsylvania State University’s Center for Dirt and Gravel Road Studies 14 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
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.
13
14
http://www.dcnr.state.pa.us/cs/groups/public/documents/document/dcnr_004055.pdf
http://www.dirtandgravel.psu.edu/
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Draft for Public Comment
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.
2. During public events and festivals
Encourage local jurisdictions to develop adequate transportation plans.
Encourage maximum movement of heavy equipment by rail to protect road systems and
prevent accidents.
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.
Require the applicant to 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.
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
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
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Draft for Public Comment
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
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.
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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% 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 used, 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 permittee shall, before beginning operations, provide the local emergency response
agency with a hazardous chemical inventory list and a copy of the Safety Data Sheets
(SDS) for all hazardous chemicals that are expected to be on-site at any stage of the
operation.
A copy of the SDS for all drilling and fracturing additives to be used shall be provided to
MDE with the application for a permit to drill a well. If the SDS does not provide the
chemical name and Chemical Abstracts Service number for each chemical in the additive,
the permit applicant shall provide that information separately.
With the exceptions noted below, the provisions regarding claims of trade secret and
disclosure of confidential information applied to drilling and hydraulic fracturing
chemicals shall be the same as those of the OSHA Hazard Communication Standard, 29
CFR 1910.1200.
1. No claim that the identity of any constituent is a trade secret shall be recognized
by MDE until the applicant provides information demonstrating, to the
satisfaction of MDE, that the claim is legitimate.
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2. The chemical name and Chemical Abstract Service (CAS) number of all
chemicals claimed to be trade secret must be provided to MDE with the permit
application; MDE will release the chemical name and CAS number only to
exposed persons or health care professions in accordance with the provisions of
the OSHA Hazard Communication Standard governing disclosure by the
chemical manufacturer, importer, or employer.
3. A health care professional’s need for the trade secret information need not relate
to occupational exposure or employees.
At the conclusion of well development, the permittee shall provide the Department with a
list of the drilling and fracturing additives actually used, and the amount of each used. In
addition, the Departments encourage well operators to disclose the identity and amount of
chemicals used on FracFocus, 15 a site managed by the Ground Water Protection Council
and Interstate Oil and Gas Compact Commission.
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 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.
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
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.
15
http://fracfocus.org/
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Draft for Public Comment
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 these
underground voids in the immediate vicinity of the proposed bore hole, while seismic
testing may be more practical for a larger area. The Departments propose that a best
practice be 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 planning shall include:
a. Selection of drill hole locations that avoid all mine voids and assures
lateral support of drill holes during drilling and casings during well
construction.
b. If such locations cannot be found, voids must be filled or isolated with
multiple concentric strings of casing and cement.
c. Unless seismic testing clearly indicates the absence of voids, a slim pilot
hole should be drilled to verify that suitable locations for production holes
have been found or could be addressed through multiple layers 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. 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
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.
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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 at the well pad.
That means that separating the cuttings from the returned drilling fluid could only 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 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.
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;
(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;
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(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 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.”
Coupling threads should meet API standards, and casing strings 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.
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2.
Isolation
The casing and cement provide zonal isolation between the well and all other subsurface
formations. The surface casing shall be run and permanently cemented to a depth at least
100 feet below the deepest known stratum bearing fresh water, or the deepest known
workable coal, whichever is deeper. All flow zones, including underground sources of
drinking water, shall be fully protected through the use of cemented intermediate well
casings, isolating the well and all drilling and produced fluids from surface waters and
aquifers, to preserve the geological seal that separates fracture network development from
aquifers, and prevent vertical movement of fluids in the annulus. The production casing
provides for a continuous conduit for injecting the hydraulic fracturing fluid and for
natural gas to flow up the well to the surface. The production casing shall be run the total
depth and length of the well and cemented.
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
and propose to require SRCBL.
Current Maryland regulations address pressure testing as follows. Each pressure test and
mechanical test of casings must be recorded in a driller’s log book. If strings of casing, in
addition to surface casing, are run in the hole, they shall be properly pressure tested.
COMAR 26.19.01.10 R and S. An applicant for a drilling permit will be required to
provide a plan for integrity and pressure testing. In addition, the Departments recommend
that mechanical integrity tests shall be performed when re-fracturing an existing well.
These provisions shall be retained.
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
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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. In addition it 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 timing on hydraulic fracturing recommendations;
however, the State realizes that this could only apply to the initiation of fracturing
operations that could be planned in advance or temporarily suspended. Once fracturing
operations have begun, it is generally not safe to halt activities.
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.
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 deyhdrators. In the federal rule,
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
completion date. By January 1, 2015, however, all sources must conduct green
completions.
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The Departments propose to require that 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. 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 permit for exploration
only, lack of a pipeline connection
2.
Flaring
When flaring is permitted during well completion, re-completions or workovers 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% 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
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
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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.)
e. For internal combustion engines that power equipment or electric
generators and which do not stay on site for more than 12 months, the
engines must comply with the requirements of either 40 CFR part 60
subpart IIII Standards of Performance for Stationary Compression Ignition
Engines or 40 CFR part 60 subpart JJJJ Standards of Performance for
Stationary Spark Ignition Internal Combustion Engines.
5.
Storage tanks
EPA recently proposed updates to the 2012 standards for storage tanks. 78 Fed. Reg.
22126 (April 12, 2013). EPA anticipates taking final action by July 31, 2013. Upon final
adoption of these regulations, the Departments propose to require that all new natural gas
operations in Maryland meet these standards upon startup.
6.
Natural Gas Star
The UMCES-AL report recommended that all operators in Maryland should voluntarily
participate in USEPA’s Natural Gas STAR program. This program is a partnership
between EPA and industry that encourages oil and natural gas companies to adopt costeffective technologies and practices that improve operational efficiency and reduce
emissions of methane. It is up to each industry partner to determine which technologies
and practices it will implement to reduce emissions. A company joins by signing a
Memorandum of Understanding, then develops an implementation plan, executes the
program, and submits annual progress reports.
No State action is necessary to allow operators to participate in the Natural Gas STAR
program.
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 flow back, moves up the wellbore to the surface. Other water that is
produced from the well after the initial flow back 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, flow back
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
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Draft for Public Comment
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%
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% 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
flow back 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) which cause a POTW to violate its own discharge limitations or which
disrupts 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. 16 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
the discharges 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.
16
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.
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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 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.
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 program must be established from wellhead to
transmission line.
Permittees shall consider all recommended strategies identified in EPA’s Natural Gas
STAR program for inclusion in a leak detection and repair program.
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
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
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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 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 activities that could be planned in advance or temporarily suspended.
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.
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 district 17 , and may be conducted at
17
“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 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
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any 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/Night 18 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 sensitive species are identified
in the Environmental Assessment, these additional measures may be necessary to protect
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
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.
18
“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
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The applicant must submit a plan with every well application for preventing the
introduction of invasive species and controlling any invasive that is introduced. The
invasive species management plan should emphasize avoidance, early detection and rapid
response. 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 plant 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
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
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Draft for Public Comment
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 Safety
Data Sheets (SDS), (formerly called Material Safety Data Sheets) 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 new 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 should be to return the developed area to native vegetation (or
pre-disturbance vegetation in the case of agricultural land returning to production) and
restore the original hydrologic conditions to the maximum extent possible. The UMCESAL Report recommended two-stage reclamation: (1) interim reclamation following
construction and drilling to stabilize the ground and reduce opportunities for invasive
42
Draft for Public Comment
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.
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.
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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, 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 a better sense of what the regulations will require.
Nevertheless, the Department can assess fees adequate to cover the expenses of
the program, including inspections.
Env. Code section 14-105 provides:
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
(3) The production of oil and gas wells installed after October 1, 2010.
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(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.
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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.
At this point of time, 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 public/private review.
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Section IX – Modifications to Permitting Procedures
Following the public review and comment period for this report, recommendations for
best practices for all aspects of natural gas exploration and production the Marcellus
Shale in Maryland will be finalized. These recommendations will then be evaluated in
light of existing permitting procedures in order to determine the necessary modifications.
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Section X – Implementing the Recommendations
Following the public review and comment period for this report, recommendations for
best practices for all aspects of natural gas exploration and production the Marcellus
Shale in Maryland will be finalized. A roadmap for implementing these recommendations
will then be developed.
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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
Stephen M. Bunker, director of Conservation Programs, Maryland Office of the Nature
Conservancy
John Fritts, Ph.D., president of the Savage River Watershed Association*
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. Fritts did not participate in the review of the best practices report.
A-1
Draft for Public Comment
APPENDIX B – COMMENTS OF THE ADVISORY COMMISSION
The purpose of the Marcellus Shale Safe Drilling Initiative Advisory Commission is to
assist State policymakers and regulators in determining whether and how gas production
from the Marcellus Shale (and, presumably, similar gas-bearing formations) can be
carried out in Maryland without unacceptably and negatively impacting public health,
safety, the environment and natural resources. The Advisory Commission’s role,
therefore, is to serve as a body with which representatives of the Department of Natural
Resources and of the Department of the Environment may consult during the
Departments’ preparation of and production of the three reports called for in Executive
Order 01.01.2011.11. The Advisory Commission helps identify and discusses issues
surrounding shale gas development. It conducts its affairs openly and transparently and
actively seeks and considers public commentary. Public comments 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 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.
This Appendix summarizes the advice of the Advisory Commission on the Best Practices
Report.
To be completed based on the comments of the Advisory Commission on the draft report.
B-1
Draft for Public Comment
APPENDIX C – RESPONSE TO PUBLIC COMMENTS
To be added after the public comments have been received and evaluated.
C-1
Draft for Public Comment
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 and draft assessment of certain constraints in
order to illustrate the potential for avoiding sensitive surface resources and while
accessing
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 and
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
Source
Public lands, Trails, Scenic By-Ways
300 feet
Surface
UMCES
600 feet
Surface
UMCES
300 feet
Surface
UMCES
Prime Agricultural Soils
0 feet
Surface
UMCES
Deep Creek Lake
2,000 feet
Surface
Local
Ordinance
Low, Medium and High Density
Residential and Institutional Uses
0 feet
Surface
DNR
Accident Dome Gas Storage Field
0 feet
Subsurface
DNR
Irreplaceable Natural Areas
(BioNet Tier 1 & 2), Wildlands
Wetlands, Vernal Pools, Streams and
Rivers
Map A identifies the areas constrained from surface development and shows only the
surface constraints. Table 1 shows that these constraints remove 60.9 % of the land
surface within the Garret and Allegany county Marcellus Shale exploration area from
surface development, leaving 39.1 % of the land area available. Map B shows the same
information, but also includes the constraints resulting from the Accident Dome Gas
Storage Field. Table 2, following the same logic as Table 1, but including constraints
associated with the Accident Dome, leaves 36.3% of the exploration area available for
surface development.
Subsurface Access Analysis
D-1
Draft for Public Comment
Based on the constraints identified above, the ability to access Marcellus shale gas
deposits through horizontal drilling was evaluated based on the UMCES citation that
each well could support an 8,000 foot horizontal drill length. Areas that remained suitable
for surface development were buffered by 8,000 feet in order to determine the extent of
Marcellus shale that was accessible. Table 1 (No Accident Dome) shows that 100% of
the Marcellus shale can be accessed under this constraint analysis. Including the Accident
Dome (Table 2) in the constraint analysis results in 97.7% subsurface shale accessibility
(Map C). A more conservative analysis, using a 4,000 foot horizontal length was also
conducted reducing subsurface accessibility to 98.2 % without considering the Accident
Dome (Table 1, Map D)) and 94.0% including the Accident Dome (Table 2, Map E).
D-2
Map A: Marcellus Shale Gas Play
All Constraints
(except Accident dome storage)
Public
Private
Garrett County
Type
Acres
Percent
39.1%
102,364
Public
Private
159,582
60.9%
Total
261,946
Allegany County
Type
Acres
Percent
23.8%
11,365
Public
Private
36,405
76.2%
Total
47,770
Table 1: Marcellus Shale Gas Play
(no Accident storage dome constraint)
Garrett
(acres)
Exploration Area
Constraint Area
Allegany
(percent)
(acres)
Total
(percent)
(acres)
(percent)
422,231
261,946
100.0%
62.0%
85,939
47,770
100.0%
55.6%
508,169
309,716
100.0%
60.9%
Public
102,364
24.2%
11,365
13.2%
113,729
22.4%
Private
159,582
37.8%
36,405
42.4%
195,987
38.6%
160,285
38.0%
38,169
44.4%
198,453
39.1%
422,231
100.0%
85,939
100.0%
508,169
100.0%
413,885
98.0%
84,903
98.8%
498,788
98.2%
Available for Operations
Subsurface gas access 8,000 feet
Subsurface gas access 4,000 feet
Map B: Marcellus Shale Gas Play
All Constraints
(including Accident dome storage)
Public
Private
Garrett County
Type
Acres
Percent
37.1%
102,364
Public
Private
173,708
62.9%
Total
276,071
Allegany County
Type
Acres
Percent
23.8%
11,365
Public
Private
36,405
76.2%
Total
47,770
Table 2 : Marcellus Shale Gas Play
(with Accident storage dome as a constraint)
Garrett
(acres)
Exploration Area
Constraint Area
Allegany
(percent)
(acres)
Total
(percent)
(acres)
(percent)
422,231
276,071
100.0%
65.4%
85,939
47,770
100.0%
55.6%
508,169
323,841
100.0%
63.7%
Public
102,364
24.2%
11,365
13.2%
113,729
22.4%
Private
173,708
41.1%
36,405
42.4%
210,113
41.3%
146,159
34.6%
38,169
44.4%
184,328
36.3%
391,249
92.7%
85,939
100.0%
477,188
93.9%
382,887
90.7%
84,903
98.8%
467,790
92.1%
Available for Operations
Subsurface gas access 8,000 feet
Subsurface gas access 4,000 feet
8,000 foot radius
Map C: Marcellus Shale Gas Play
All Constraints
(including Accident dome storage)
Public
Private
Subsurface gas accessible
within 8,000 feet
4,000 foot radius
Map D: Marcellus Shale Gas Play
All Constraints
(except Accident dome storage)
Public
Private
Subsurface gas accessible
within 4,000 feet
4,000 foot radius
Map E: Marcellus Shale Gas Play
All Constraints
(including Accident dome storage)
Public
Private
Subsurface gas accessible
within 4,000 feet
Draft for Public Comment
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). 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.
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, picnicing/cookout, sightseeing and photography.
Figure 1. Total trip spending profile by region (Dougherty, 2011).
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
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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 of or ability for these activities to be
conducted. If wildlife is impacted or scared off 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.
Following discussions with Maryland Department of Natural Resource (DNR) staff
related to these additional considerations, there are 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;
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.
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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. Particularly, 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. With the recent completion of
UMCES' report, there is now an opportunity to reach out to Marylanders and inform them
about the state of the industry, plans for safe development of shale gas and provide
opportunities for citizens to submit feedback and learn about work to date.
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. As noted in previous sections,
participatory mapping workshops could also be conducted to identify particular areas
where recreational and aesthetic impacts would most likely intersect with the expansion
of the shale gas industry.
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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 sitespecific 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
pre-development 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 resource. Spacing
Section III, Comprehensive Gas
Development Plans (CGDP) adopts
this recommendation; however,
limiting the disturbance to 1-2% of the
land appears as a planning principle
for high value watersheds and the
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Draft for Public Comment
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% 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.
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 private groundwater
wells and recommend pre-drilling
planning and use of pilot holes to
evaluate subsurface hazards, such as
deep coal mines.
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 groundwater 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 groundwater
sampling.
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Draft for Public Comment
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.
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Draft for Public Comment
1-K Maryland should develop regulations
Section VI R, Engineering, Design
that force rapid partial reclamation (including
and Environmental Controls and
revegetating disturbed areas surrounding wells
Standards adopt this recommendation
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.
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.
F-4
Draft for Public Comment
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 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.
Leak Detection is required in Section VI
L, Engineering, Design and
Environmental Controls and Standards,
and operators will need to meet
monitoring, reporting and recordkeeping
requirements as referenced in Section
VII, Monitoring, Recordkeeping and
Reporting.
2-B Encourage operators to either use
newer internal combustion engines or convert
from diesel internal combustion engines to
electric motors for operating drilling rigs,
pumps, and compressors wherever possible by
implementing “fleet average” emission
standards for NOx, VOCs, and PM2.5.
Section VI E and J, Engineering, Design
and Environmental Controls and
Standards accepts this recommendation.
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.
No State action is necessary to allow
operators to voluntarily participate in
EPA’s Natural Gas STAR program.
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.
Section V, Plan For Each Well accepts
this recommendation.
F-5
Draft for Public Comment
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.
F-6
Draft for Public Comment
3-F
Use of BOPE with two or more
redundant mechanisms should be considered a
best practice for MSGD in Maryland.
Section VI G, Engineering, Design and
Environmental Controls and Standards
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, 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.
Section VI H, Engineering, Design and
Environmental Controls and Standards
and Section VII, Monitoring,
Recordkeeping and Reporting accepts
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
groundwater), 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
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Draft for Public Comment
includes private wells. The setback
should apply from the edge of any
drinking water reservoir and upstream
of any drinking water intake on a freeflowing stream.
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 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.
4-C Pre-drilling groundwater 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 groundwater 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
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
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Draft for Public Comment
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.
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
Section VI A, Engineering, Design and
stormwater structures should occur prior to well Environmental Controls and Standards.
drilling and 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.
F-9
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.
Draft for Public Comment
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 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.
These recommendations are accepted
in Section VI C and K, Engineering,
Design and Environmental Controls
and Standards.
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.
F-10
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
Draft for Public Comment
5-A.1 Concentrate operations
Section III, Comprehensive Gas
including roads on disturbed and open lands,
Development Plans (CGDP) adopts this
ideally in locations zoned for industrial activity recommendation.
and/or close proximity to major roads.
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
Section III, Comprehensive Gas
planning process to address the cumulative
Development Plans (CGDP) adopts this
impact of multiple projects, to channel
recommendation.
development into areas with greater amounts
of existing disturbance, and to avoid areas with
intact forests (especially forest interior
habitat).
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 chemicals and wastewater.
This recommendation is accepted in
Section VI A and P, Engineering,
Design 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 accept the
proposed location restrictions and
setbacks recommendation.
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.
F-11
Draft for Public Comment
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 Section VI M. Engineering, Design and
drill pad sites by restricting night lighting to
Environmental Controls and Standards
only when necessary and to only the amount of accepts this recommendation.
lighting 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 1,000ft of aquatic habitat, vegetative
screens and additional lighting restrictions
could be required to reduce light pollution into
these sensitive areas.
Section VI M, Engineering, Design and
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.
F-12
Draft for Public Comment
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 accepts
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 Section III, Comprehensive Gas
for shale gas development should not be
Development Plans (CGDP) adopts
permitted.
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 accepts this
recommendation.
6-C Data that describe the biological
resources of western Maryland should be
developed and made available to MSGD
applicants. These data should be used to
effectively channel development away from
high-value biological resources and into
industrial zones accessible via existing roads
and highways.
Section III, Comprehensive Gas
Development Plans (CGDP) adopts
this recommendation.
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%
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.
F-13
Draft for Public Comment
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 zeroSection VI A and E, Engineering
discharge drilling pads on which all drilling and Design and Environmental Controls
hydraulic fracturing fluids, chemicals, and
accepts this recommendation.
liquid wastes are 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 DCNR recommendations could be
adopted:
Section III, Comprehensive Gas
Development Plans (CGDP) and
Section VI A, Engineering Design and
Environmental Controls accepts this
recommendation.
F-14
Draft for Public Comment
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 This recommendation is addressed in
a way of reducing rutting and maintaining
Section VI A, Engineering Design and
subbase stability.
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 as possible from homes, businesses,
public buildings, or places with high levels of
recreational activity (e.g., hiking trails, parks,
picnic areas, etc.) (see Chapter 9 also).
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
7-A.2 Best management practices in
This recommendation is accepted in
well construction (e.g., casing and cementing) Section VI F, Engineering Design and
should be followed to ensure wellbore integrity Environmental Controls.
and isolation (see Chapter 3).
F-15
Draft for Public Comment
7-A.3 Proper monitoring and predevelopment assessment are important steps to
limit the migration of hydrocarbons, brines, or
hydraulic fracturing fluids into groundwater,
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 This recommendation is accepted in
develop site-specific, emergency response
Section VI P, Engineering Design and
plans (ERP) that describes in detail how a
Environmental Controls.
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.
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
This recommendation is accepted in
variations on standard responses demonstrating Section VI P, Engineering Design and
sensitivity to weather, time of day, time of
Environmental Controls.
year, and the particular geography of sites
(e.g., topographic and soil conditions).
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 a 6 ft high chained link or equivalent),
gates (with keyed locks), and signage in place
around drill rigs, engines, compressors, tanks,
impoundments, and separators, to restrict
public access.
This recommendation is accepted in
Section VI Q, Engineering Design and
Environmental Controls.
F-16
Draft for Public Comment
7-C.2 Use of safety or security guards This recommendation is accepted in
to further control access (particularly important Section VI Q, Engineering Design and
during active drilling and completion phases of Environmental Controls.
an operation).
7-C.3 Duplicate keys to all locks
should be provided to the regulatory agency
and to local emergency responders.
This recommendation is accepted in
Section VI Q, Engineering Design and
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
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
F-17
Draft for Public Comment
familiar with the resources that could be
impaired by shale gas development.
8-C Applicants should be required to
submit a visual resource mitigation plan as
part of the permit application process based on
site-specific assessment ( i.e., viewshed
analysis).
Section IV B, Location Restrictions and
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
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
F-18
Draft for Public Comment
development zones.
Controls for lighting
8-I
Any permitted shale gas development
activities in the vicinity of public recreational
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.
Section VI E, Engineering, Design and
Environmental Controls. 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.
Chapter 9 – Protecting quality of life and aesthetic values
UMCES-AL
MDE and DNR
9-A Well-pad siting should consider the
multiple factors that influence the quality of
life and aesthetics of rural life in western
Maryland (e.g., location of existing
infrastructure, traffic loads on existing roads,
etc.)
Section III, Comprehensive Gas
Development Plans (CGDP) adopts this
recommendation.
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
Section III, Comprehensive Gas
proximity to major interstate highways and exit Development Plans (CGDP) adopts this
ramps designed to efficiently handle round-the- recommendation.
clock transportation
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.
F-19
Draft for Public Comment
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
diesel-powered 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 to avoid or minimize the greatest
conflicts between the public and MSGD.
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.
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 This recommendation is accepted in
sound barriers where natural noise attenuation
Section VI N, Engineering, Design and
would be inadequate.
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.
F-20
Draft for Public Comment
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 (e.g., the use of visual screens,
camouflages, paint schemes, evergreen buffers,
and landscaping techniques) to minimize
degradation of western Maryland viewsheds by
MSGD.
This recommendation is accepted in
Section IV B, Location Restrictions
and Setbacks.
Chapter 10 – Protecting agriculture and grazing
UMES-AL
MDE and DNR
10-A Soil conditions at sites being
considered for shale gas development should
be evaluated as part of the planning process.
This recommendation is accepted in
Section IV B, Location Restrictions and
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
This recommendation is accepted in
Section VI R, Engineering, Design and
Environmental Controls and Standards.
F-21
Draft for Public Comment
times.
10-F Operators must fence livestock out of
gas development areas.
F-22
This recommendation is accepted in
Section VI Q, Engineering, Design and
Environmental Controls and Standards.
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