Draft Report

Draft Report
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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
i
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
ii
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
EXECUTIVE SUMMARY ................................................................................... III
SECTION I – ORGANIZATION OF THE REPORT............................................. 1
SECTION II – OVERVIEW.................................................................................... 2
A.
B.
C.
D.
MARCELLUS SHALE ........................................................................................... 2
DEVELOPMENTS IN MARYLAND .................................................................... 2
THE EXECUTIVE ORDER AND THE ADVISORY COMMISSION................. 3
THE WORK OF THE ADVISORY COMMISSION ............................................. 4
SECTION III – COMPREHENSIVE GAS DEVELOPMENT PLANS................. 7
A.
B.
C.
D.
APPLICATION CRITERIA AND SCOPE ............................................................ 7
PLANNING PRINCIPLES ..................................................................................... 8
PROCEDURE AND APPROVAL PROCESS ....................................................... 8
REGULATORY AND NON-REGULATORY BENEFITS................................... 9
SECTION IV – LOCATION RESTRICTIONS AND SETBACKS..................... 10
A. LOCATION RESTRICTIONS AND SETBACKS .............................................. 10
B. SITING BEST PRACTICES................................................................................. 13
SECTION V – PLAN FOR EACH WELL............................................................ 14
SECTION VI – ENGINEERING, DESIGN AND ENVIRONMENTAL
CONTROLS AND STANDARDS........................................................................ 16
A. SITE CONSTRUCTION AND SEDIMENT AND EROSION CONTROL ........ 16
1.
The pad......................................................................................................... 16
2.
Tanks and containers.................................................................................... 17
3.
Pits and Ponds .............................................................................................. 17
4.
Pipelines....................................................................................................... 17
5.
Road Construction ....................................................................................... 18
6.
Ancillary equipment..................................................................................... 19
A. TRANSPORTATION PLANNING ...................................................................... 19
B. WATER ................................................................................................................. 20
1.
Storage ......................................................................................................... 20
2.
Water withdrawal......................................................................................... 20
3.
Water reuse .................................................................................................. 21
C. CHEMICAL DISCLOSURE................................................................................. 22
D. DRILLING ............................................................................................................ 23
1.
Use of electricity from the grid.................................................................... 23
2.
Initiation of drilling...................................................................................... 23
3.
Pilot hole ...................................................................................................... 23
4.
Drilling fluids and cuttings .......................................................................... 24
5.
Open hole logging........................................................................................ 25
E. CASING AND CEMENT ..................................................................................... 25
UMCES-AL REPORT RECOMMENDATIONS 3-C, 3-D, 3-E, 3-F, 5-D.1, 9-D.2 ... 25
1.
Requirements for casing and cement ........................................................... 25
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2.
Isolation........................................................................................................ 26
3. Cased-hole logging, Integrity testing and Pressure testing.......................... 26
F. BLOWOUT PREVENTION ................................................................................. 27
G. FRACKING........................................................................................................... 27
H. FLOWBACK AND PRODUCED WATER ......................................................... 27
I. AIR EMISSIONS .................................................................................................. 27
1.
Green Completion or Reduced Emissions Completion ............................... 28
2.
Flaring .......................................................................................................... 28
3.
Electricity from the grid............................................................................... 28
4.
Engines......................................................................................................... 28
5.
Storage tanks................................................................................................ 29
6.
Natural Gas Star........................................................................................... 29
J. WASTEWATER TREATMENT AND DISPOSAL ............................................ 29
K. LEAK DETECTION ............................................................................................. 31
L. LIGHT ................................................................................................................... 31
M. NOISE ................................................................................................................... 31
UMCES-AL REPORT RECOMMENDATION 9-B, 9-D-3, 9-D-4, 9-D-5................. 31
N. INVASIVE SPECIES............................................................................................ 33
O. SPILL PREVENTION, CONTROL AND COUNTERMEASURES AND
EMERGENCY RESPONSE ................................................................................. 33
P. SITE SECURITY .................................................................................................. 34
Q. CLOSURE AND RECLAMATION BOTH INTERIM AND FINAL ................. 35
SECTION VII – MONITORING, RECORDKEEPING AND REPORTING...... 36
SECTION VIII – MISCELLANEOUS RECOMMENDATIONS........................ 38
A. ZONING ................................................................................................................ 38
B. FINANCIAL ASSURANCE................................................................................. 38
C. FORCED POOLING ............................................................................................. 38
SECTION IX – MODIFICATIONS TO PERMITTING PROCEDURES ........... 39
SECTION X – IMPLEMENTING THE RECOMMENDATIONS...................... 40
APPENDIX A – MEMBERS OF THE COMMISSION......................................... 1
APPENDIX B – CONSULTATION WITH THE ADVISORY COMMISSION... 1
APPENDIX C – UMCES-AL REPORT ................................................................. 1
APPENDIX D – MARCELLUS SHALE CONSTRAINT ANALYSIS ................ 1
APPENDIX E – MARCELLUS SHALE AND RECREATIONAL AND
AESTHETIC RESOURCES IN WESTERN MARYLAND .................................. 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 this report, MDE entered into a Memorandum of Understanding with the University
of Maryland Center for Environmental Science, Appalachian Laboratory, to survey best
practices from several states and other sources, and to recommend a suite of best
practices appropriate for Maryland. That report was completed in February 2013.The
Departments evaluated whether to add to, accept, reject, or modify the suggestions, based
on a number of factors. A draft was made available for public comment on _________,
2013. After consideration of the comments, the Departments submit this report on Part II
of the study, Best Practices.
[Add the remainder of the Executive Summary after the report is complete.]
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Section I – Organization of the Report
The UMCES-AL Report is organized into ten chapters, each devoted to protecting one
aspect of the environment, natural resources, public health and safety. In order to
facilitate incorporation the recommendations into a regulatory and permitting program,
however, we have chosen to organize this report differently.
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 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, monitoring during drilling and fracking 1 , and monitoring during
the production phase 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 a summary of the position of the Advisory Commission on
the draft recommendations and a response to comments on the draft report. and
1
The correct spelling is “fracing” but the alternate spelling “fracking” has become common and is used
herein.
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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 hydraulic fracturing
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 high-volume hydraulic fracturing began around 2005 in
Pennsylvania and has accelerated rapidly.
The production of natural gas has the potential to benefit Maryland and the United States.
By tapping domestic sources, it 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 hydraulic fracturing 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 hydraulic fracturing 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.
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The Maryland Departments of the Environment (MDE) and Natural Resources (DNR)
have roles in the evaluation of natural gas projects. Each would be involved in any future
permitting decisions for drilling in the Marcellus Shale.
The mission of the Maryland Department of the Environment is to protect and restore the
quality of Maryland’s air, water, and land resources, while fostering smart growth,
economic development, healthy and safe communities, and quality environmental
education for the benefit of the environment, public health, and future generations. In
addition, MDE is specifically authorized by statute to issue permits for gas exploration
and production. The Department of the Environment is required to coordinate with the
Department of Natural Resources in its evaluation of the environmental assessment of
any proposed oil or gas well.
The Department of Natural Resources leads Maryland in securing a sustainable future for
our environment, society, and economy by preserving, protecting, restoring, and
enhancing the State’s natural resources. In addition, DNR owns or has conservation
easements on substantial acreage in the State, including western Maryland.
The first application for a permit to produce gas from the Marcellus Shale in Maryland
using horizontal drilling and high volume hydraulic fracturing was received in 2009. 2 To
address the need for information to evaluate these permit applications properly, the
Governor issued the Marcellus Shale Safe Drilling Initiative in Executive Order
01.01.2011.11 on June 6, 2011.
C. The Executive Order and the Advisory Commission
Executive Order 01.01.2011.11 directs MDE and DNR to assemble and consult with an
Advisory Commission in the study of specific topics related to horizontal drilling and
hydraulic fracturing in the Marcellus Shale. 3 The Advisory Commission is to assist State
policymakers and regulators in determining whether and how gas production from the
Marcellus Shale in Maryland can be accomplished without unacceptable risks of adverse
impacts to public health, safety, the environment, and natural resources. The Advisory
Commission includes a broad range of stakeholders. Members include elected officials
from Allegany and Garrett Counties, two members of the General Assembly,
representatives of the scientific community, the gas industry, business, agriculture,
environmental organizations, citizens, and a State agency. A representative of the public
health community was added in 2013. Appendix A is a list of the Commissioners.
The Executive Order tasks MDE and DNR, in consultation with the Advisory
Commission, with conducting a three-part study and reporting findings and
recommendations. The Commission is staffed by DNR and MDE. The completed study
will include:
2
Additional applications were received in 2011. Applications for a total of seven wells were received by
MDE, but all have been withdrawn. In general, drilling has migrated to areas where not only natural gas,
but also natural gas liquids that are more valuable, can be produced from formations.
3
Although the Governor’s Executive Order is directed specifically at the Marcellus Shale and hydraulic
fracturing, there is a potential for gas extraction from other tight shale gas formations, including the Utica
Shale, and by well stimulation techniques other than hydraulic fracturing. The findings and conclusions
regarding gas exploration in the Marcellus Shale may also apply to other formations and techniques.
3
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(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;
(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, 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. In preparation for this 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 principal investigators were Keith N.
Eshleman, Ph.D. and Andrew Elmore, Ph.D. Their report, Recommended Best
Management Practices for Marcellus Shale Development in Maryland (UMCES-AL
Report), was completed in February 2013. It is attached as Appendix C. 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 suggestions, based on a number
of factors, including the opinions of the Advisory Commission, the degree of
environmental protection, technical feasibility, practicality, and the Departments’
capacity to implement the recommendations and integrate them into their programs.
D. The Work of the Advisory Commission
The Governor announced the membership of the Advisory Commission in July, 2011,
and the Commission has met on numerous occasions. Most meetings were in Allegany or
Garrett Counties, but two were held in Hagerstown and __ in Annapolis. The
Departments have provided written information and briefings to the Advisory
Commission on issues relating to hydraulic fracturing. 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
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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.
DNR conducted an intensive environmental assessment of Garrett County to identify
community water supplies, stronghold watersheds, high quality streams, State lands, trail
networks, recreational assets, landscape values, ecological resources, forest interior
dwelling species, threatened and endangered plants and animals and areas of particular
scenic value that could be impacted, directly or indirectly, by drill pads, pipeline/road
construction and use.
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. This effort is ongoing. The
Departments and the Advisory Commission coordinated with representatives of the
House Environmental Matters Committee and the Senate Education, Health and
Environment Committee.
In the 2013 session of the General Assembly, [describe bills]
Describe additional funding and plans for future work
In furtherance of developing Best Practices recommendations, MDE contracted with the
University of Maryland Center for Environmental Science, Appalachian Laboratory, to
research best practices and recommend a suite of 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, (the UMCES-AL
Report), was made available to the Commission and the public in February, 2013 and is
included as Appendix C.
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
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For the final report
A draft was made available for public comment on _________, 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 Departments decided
whether to add to, accept, reject, or modify the recommendations based on a number of
factors, including the opinions of the Advisory Commission, the expertise of
Departmental staff, and judgments about environmental protection, technical
practicability, and administrative feasibility. The 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 modify its laws and regulations on gas exploration and development to
institute a voluntary program whereby a company holding gas interests could prepare and
submit for State approval a comprehensive drilling plan for all its holdings 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 recommend that Maryland should require, as a prerequisite to the issuance of any
permit to drill a gas production well, that the prospective applicant first submit a
Comprehensive Gas Development Plan (CGDP). This plan would include all land for
which the prospective applicant has the right to extract natural gas, and cover a period of
at least 10 years. More than one entity could prepare a CGDP for an assemblage of land
in which multiple entities hold mineral rights.
Comprehensive Gas Development Plans (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, many of the
concerns associated with maintaining the rural character of western Maryland, protecting
high value natural resources and resource-based economies and minimizing public use
conflicts can be resolved or minimized while allowing for responsible energy
development. 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 entire area of the target formation for which the applicant holds gas rights
and areas needed for additional supporting infrastructure (compressor stations, waste
water treatment facilities, roads, pipelines, etc.).
2.
The CGDP shall cover a period of at least five years of development.
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3.
Companies whose geographic planning units overlap are encouraged to develop
integrated plans to improve use of existing and new infrastructure and to minimize
cumulative impacts.
4.
A company is not obligated to develop all the pads or wells identified in the plan.
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.
Concentrate operations on disturbed, open lands or lands zoned for industrial
activity
5.
Co-locate linear infrastructure with existing roads, pipelines and power lines.
6.
Reduce cumulative surface impacts that consider impacts from other gas
development projects and land use conversion activities.
7.
Avoid surface development beyond 2% of the watershed area in high value
watersheds.
8.
Minimize fragmentation of intact forest, with particular emphasis on interior
forest habitat.
9.
Additional planning elements include
a)
Area wide transportation plan.
b)
Water supply and waste management plans
c)
Sequence of well drilling over the lifetime of the plan that places priority on
locating early well pads in areas removed from sensitive natural resource values.
d)
Consistency with local zoning ordinances and comprehensive planning elements.
e)
Identification of all federal, state and local permits.
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 includes 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.
Comprehensive planning GIS data will be provided through a Shale Gas
Development Toolbox.
4.
State agencies and local government agencies review the CDGP, evaluate
opportunities for coordinated regulatory review and present comments to the applicant to
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direct any needed alternative analyses for review. This review will be completed within
45 days of submission by the applicant of the CDGP.
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 is 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.
8.
Additional modifications to the plan are prepared based on alternatives analyses
and public comment.
9.
The State approves or disapproves the CGDP; upon approval, the applicant may
file a permit application for one or more wells.
10.
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 of a
modified CGDP application; however a change in the sequence of execution shall not
require a modified application.
D. Regulatory and Non-regulatory Benefits
1.
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:
2.
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, erosion and sediment control, stormwater management, water appropriation and
use, etc.
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.
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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
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 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
MDNR 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 4,000 foot
horizontal drill length, resulting in about 94 % accessibility to the Marcellus shale
formation. This assessment supports the UMCES 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.
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Setback Recommendations from UMCES-AL Report (Reference to Chapters omitted)
From
To
Distance (ft)
Aquatic habitat (defined as all streams,
rivers, seeps, springs, wetlands, lakes,
ponds, reservoirs, and floodplains)
Edge of drill pad disturbance
300
Special conservation areas (e.g.,
irreplaceable natural areas, wildlands)
Edge of drill pad disturbance
600
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
300
Mapped limestone outcrops or known
caves
Borehole
1,000
Mapped underground coal mines
Borehole
1,000
Historic gas wells
Any portion of the borehole,
including laterals
1,320
Any occupied building
Compressor stations
1,000
Any occupied building
Borehole
1,000
Private groundwater wells
Borehole
500
Public groundwater wells or surface water
intakes
Borehole
2,000
The Departments generally accept the proposed location restrictions and setbacks with
the following modifications and additions.
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.
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
the limestone formation – the
Greenbriar – will not be encountered
(see figure to left). This setback
recommendation was established to
avoid karst features. However, MGS
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
downdip side
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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.
3.
Setbacks for known and discovered caves should remain at 1000 feet because of
the biological resource sensitivity and the potential for groundwater contamination.
4.
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
involves careful site evaluation and pilot hole investigations. See Section VI-D for a
description on pre-drill planning.
5.
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.
6.
Reevaluate the setbacks associated with public drinking water reservoirs since
current regulations impose setbacks from a drinking water intake but not the edge of the
reservoir. Setbacks should be at least as protective as the recommended setback of 2,000
feet from public drinking water wells.
7.
Expand drill pad location restrictions and setbacks listed in Table 1-1 to all gas
development activities resulting in surface disturbance. This includes roads, pipelines,
compressor stations, separator facilities and other infrastructure needs. This expansion
specifically applies to aquatic habitat, special conservation areas, cultural and historical
sites, State and federal parks and forests, trails, wildlife management areas, scenic and
wild rivers and scenic byways.
8.
MDNR will develop new maps of public outdoor recreational use areas to
establish additional recreational setbacks and mitigation measures for minimizing public
use conflicts. MDNR 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
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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. MDNR 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.
B. Siting Best Practices
UMCES-AL Report recommendations 3-B, 4-D, 5-A.2, 5-D, 5-F. 5-F.1, 6-J.2, 6-J.4, 8-C,
8-D, 8-H, 8-I, 9-G, 9-H, 10-A, 10-B, 10-C, 10-D
This also includes best practices recommended for siting pipelines, access roads and
other supporting infrastructure. The Departments generally accept the proposed siting
best practices and with the following modifications and additions.
1. Determine if no-net-loss of forest should apply to temporary or permanent losses
and define how the acreage should be determined.
2. 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.
3. MDNR will provide additional GIS conservation planning data layers and
guidance for avoiding, minimizing and mitigating impact to aquatic and terrestrial
high priority conservation areas.
4. Develop siting policies 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.
5. Stream crossings will avoid impact to brook trout spawning beds (mentioned in
report, but not listed in key recommendations).
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, 5-B.2
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 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 adequate. The plan must address, at a
minimum,
1. Updating the Environmental Assessment
This effort is includes all environmental assessment baseline monitoring and site
characterization required as a prerequisite for issuing individual well permits.
The relevant UMCES recommendations are also reflected in Section VII –
Monitoring, Recordkeeping and Reporting. 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. Acquisition of water
4. Evaluation of potential flow zones
5. Identification and evaluation of shallow and deep hazards
6. Pore pressure/fracture gradient/drilling fluid weight
7. Monitoring and maintaining wellbore stability
8. Addressing lost circulation
9. Casing
10. Cementing
11. Drilling fluids
12. Wellbore hydraulics
13. Barrier design
14. Integrity and pressure testing
15. Blow out protection
16. Contingency planning
17. Communications plan, including communication with contractors and
subcontractors
18. Site security
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19. Storage, treatment and disposal of water, wastewater, fuel and chemicals
20. Road construction and transportation planning
21. Spill prevention, control and countermeasures, and emergency response
22. Invasive species
23. Waste handling, treatment and disposal
24. Monitoring the well during production to detect well problems and failure of
casing or cement
25. Reclamation
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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 are constantly evolving and improving.
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-I, 5-B, 5-B.1, 5-B.2, 6-G, 6-J.1, 6-J.3,
6-J, 6-K, 7-A.2, 9-D, 9-F
The proper construction of drilling pads, roads, pipelines, tanks, pits and ponds, 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. 4 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. 5 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 fracking. 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 fracking 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 impermeable berms 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 may cease only
4
5
COMAR 26.19.01.10 J through K.
COMAR 26.19.01.06C (12) and (13).
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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.
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
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
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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 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 follow comply with 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.
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
UMCES-AL Report recommendations 6-J, 9-F
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,
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
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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 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 plan will provide assurance that erosion will be controlled..
The Departments are considering two options for construction standards for roads
constructed by private parties to facilitate gas exploration and production:
c. The recommendations of the Pennsylvania Department of Conservation and
Natural Resources; or
d. Cornell University Transportation Center
6.
Ancillary equipment
Ancillary equipment includes gathering and boosting station, 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 the air emissions section, below.
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
Garrett County have existing programs to allow for emergency transport of heavy or
oversized equipment during off-hour periods. Allegany County may have a similar
program. The Departments accept the proposed transportation planning recommendations
with the following modifications and additions to minimize use conflicts and provide
adequate mitigation for road damage.
State public land managers should coordinate the timing of oil and gas activities with the
operator to avoid public conflict and to minimize damage to roads on public lands. Public
land managers should consider suspending activities requiring heavy trucking during:
1. Periods of heavy public use such as hunting season or trout season
2. Weather conditions that make the roads impassable
3. Traditionally wet periods when road damage is most probable
4. During the spring frost breakup
Note: Trucking should be closely monitored during high-use and wet periods if it is not
possible to suspend activities.
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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
Ensure that local governments are adequately equipped for responsive and adequate
transportation planning. This may require State agency technical and financial assistance.
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 1-L, 4-G, 9-A, 4-G
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. See 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
UMCES-AL Report recommendations I-L, 4-G, 6-H.1, 6-H.2
The UMCES-AL Report recommends that Maryland revise its oil and gas permitting
regulations to explicitly address water withdrawal issues. In particular, they recommend a
quantitative analysis of acceptable water withdrawals to ensure that all users of the
resource are protected and that water withdrawal should occur only from the region’s
large rivers and perhaps from some reservoirs. For the reasons explained below, the
Departments do not see a need to incorporate water appropriation provisions in MDE’s
oil and gas regulations.
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 these are
necessary practices.
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The Maryland legislature had determined that it is necessary to control the appropriation
or use of surface or ground water 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 the Department 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 (1,825,000
gallons per year) as an annual average of ground water. Appropriation requests for an
annual average withdrawal of more than 10,000 gallons per day (gpd) (as a new request
or increase) may be required to perform aquifer testing and other technical analysis. 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.
The Susquehanna River Basin Commission (SRBC) issues water appropriation permits
for withdrawals of surface or ground water in that basin. The SRBC has a regulatory
threshold of 100,000 gpd as a 30-day average, and 20,000 gpd for 30 day consumptive
uses; however, in 2008 it amended its regulations to require natural gas companies to
seek approval from the SRBC before withdrawing or using any amount of water for
unconventional natural gas development. The Departments believe that Maryland’s
current thresholds are adequately protective, but requests comments on whether it should
adopt a threshold criterion for unconventional natural gas development to match that of
the SRBC.
The Departments also believe that the substantive criteria for evaluating applications for
water appropriation are adequate to address water withdrawals for Marcellus shale
drilling and hydraulic fracturing. These criteria are set forth in COMAR 26.17.06.05. The
Department of the Environment has the authority to include protective provisions in
permits. COMAR 26.17.06.06.
3.
Water reuse
UMCES-AL Report recommendations 4-J
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,
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because this would decrease truck transport and associated impacts. The Departments
agree.
Flowback and produced water shall be recycled to the maximum extent practicable,
which shall not be less than 90%, and on the pad site of generation to the extent feasible.
D. Chemical Disclosure
UMCES-AL Report recommendations 4-H, 7-B
The only recommendations made about disclosure of chemicals in the UMCES-AL report
(4-H and 7-B) related 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 fracking 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) or propping agents
for hydraulic fracturing. 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 Department 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 identification:
Safety Data Sheets (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 Abstract 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 fracking chemicals shall be
the same as those of the OSHA Hazard Communication Standard, 29 CFR 1910.1200
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
The chemical name and Chemical Abstract Service number of all chemicals claimed to
be trade secret must be provided to MDE with the permit application; MDE will release it
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.
A health care professional’s need for the trade secret information need not relate to
occupational exposure or employees.
In addition, the Departments encourage well operators to disclose the identity and amount
of chemicals used on Frac Focus, a site managed by the Ground Water Protection
Council and Interstate Oil and Gas Compact Commission.
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E. Drilling
1.
Use of electricity from the grid
UMCES-AL Report recommendations 2-B, 9-D, 9-D-1
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
Departments have not yet developed any criteria for deciding when electricity “could be
made readily available” and solicits comments or suggestions for this determination.
The use of propane or natural gas to power motors and pumps should be encouraged if
electricity from the grid is not available.
2.
Initiation of drilling
UMCES-AL Report recommendations 5-D.1, 8-I, 9-D.2
The UMCES-AL report recommended that drilling should avoiding times of peak
outdoor recreational periods such as holiday weekends, first day of trout season, and
during sensitive migratory or mating seasons.
The Departments accept the proposed timing on drilling recommendations with the
following modification; however, the State realizes that this could only apply to the
initiation of a drilling or fracturing operation or other activities that could be planned in
advance or temporarily suspended. Once drilling and fracturing operations have begun, it
is generally not safe to halt activities.
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. They propose that a best practice be to conduct pre-drill planning in
any area where underground mining is suspect which should require:
e. Careful search for and geo-referencing of any mine maps for any mines
within 500 feet of prospective drill holes.
f. Selection of drill hole locations that avoid all mine voids and assures lateral
support of drill holes during drilling and casings during well construction.
g. If such locations cannot be found concrete mine voids to provide such
locations and require double or triple casing through the mining zone.
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h. In all cases, a slim pilot hole should be drilled through any suspected mining
zones to verify that suitable locations for production holes have been found
or created by concreting mine voids.
4.
Drilling fluids and cuttings
UMCES-AL Report recommendation 6-G
The UMCES-AL Report notes that high pressure air can 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, 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.
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 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 may be used
while drilling these intervals. Below the cemented surface casing that isolates the deepest
stratum bearing fresh water, additives other than those suitable for drilling through
potable water can be used if approved by the Department.
A best practice for managing cuttings is to contain the drilling fluid, returned drilling
fluid and 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 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 think that they should also be tested for other contaminants, including
sulfates and salinity before disposal and disposed of in compliance with the law. If the
cuttings show no elevated levels of radioactivity, and meet other criteria established by
MDE, however, onsite disposal of the cuttings could be allowed.
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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 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;
(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, 3-F, 5-D.1, 9-D.2
1.
Requirements for casing and cement
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 (ASTM) in
“A500/A500M Standard Specification for Cold-Formed Welded and Seamless Carbon
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Steel Structural Tubing in Rounds and Shapes” and has 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.”
Reconditioned casing may be permanently set in a well only it has passed a hydrostatical
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 the inspector before the casing is installed in the well.
2.
Isolation
The casing and cement provide zonal isolation between the well and all other subsurface
formations. 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 fracking 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.
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. Section V of this report requires the applicant for a
drilling permit to provide a plan for integrity and pressure testing. In addition, the
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Departments recommend that mechanical integrity tests shall be performed when
refracturing an existing well.
G. Blowout Prevention
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 (kick) 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.
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. Fracking
Diesel fuel shall not be used in fracking fluids
The UMCES-AL report recommended that fracking should avoid times of peak outdoor
recreational periods such as holiday weekends, first day of trout season, and during
sensitive migratory or mating seasons.
The Departments accept the proposed timing on fracking recommendations; however, the
State realizes that this could only apply to the initiation of fracturing operation that could
be planned in advance or temporarily suspended. Once fracturing operations have begun,
it is generally not safe to halt activities.
A tilt meter or microseismic survey shall be performed by the permittee for the first well
fracked on each pad to provide information on the extent, geometry and location of
fracturing; the information shall be provided to MDE.
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
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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.
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:
i. Inadequate water disposal capacity
j. Undersized flowback equipment
k. 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
Electrically-powered equipment must be used wherever line power is available (or could
be made readily available) from the grid. The use of propane or natural gas to power
motors and pumps should be encouraged if electricity from the grid is not available
4.
Engines
a. All on-road and non-road vehicles and equipment using diesel fuel must
use Ultra-Low Diesel fuel (maximum sulfur content of 15 ppm)
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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
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
In addition, on March 28, 2013, EPA proposed updates to the 2012 standards for storage
tanks. EPA anticipates taking final action by July 31, 2013. Upon final adoption of these
regulations, the Departments propose to require that facilities in Maryland meet these
standards upon startup.
6.
Natural Gas Star
UMCES-AL Report 2-A
The UMCES-AL report recommended that all operators in Maryland should voluntarily
participate in USEPA’s Natural Gas STAR program. This program is a voluntary
partnership between EPA and industry that encourages oil and natural gas companies to
adopt cost-effective technologies and practices that improve operational efficiency and
reduce emissions of methane. It is up to each 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. The Departments solicit comment on whether it should make any parts of the
program mandatory for companies operating in Maryland.
K. Wastewater Treatment and Disposal
UMCES-AL Report recommendations 4-J, 4-K
After a well is fracked, some portion of the fracking 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
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dissolved solids (TDS), fracturing fluid additives, metals, and naturally occurring
radioactive materials. Typically, flow back contains significant concentrations of
dissolved sodium, calcium, and 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
Operators have been moving toward recycling of gas development wastewaters, and
reusing them for fracking. 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, as a best practice, flowback and produced water be
recycled to the maximum extent practicable, which shall not be less than 90%, and on the
pad site of generation to the extent feasible.
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. To evaluate this recommendation, it is necessary to understand the
regulation of direct and indirect discharges of pollutants.
Direct and indirect discharge 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.6 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 fresh water streams, where they could kill or damage the aquatic
6
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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organisms. Where the discharges were above 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.
With regard to disposal in Class II injection wells, the 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.
L. Leak Detection
UMCES-AL Report recommendations 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.
Require consideration of all feasible recommended strategies identified in EPA’s Natural
Gas STAR program as an element of 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 as discussed in the monitoring section is 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 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.
N. Noise
UMCES-AL Report recommendation 9-B, 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
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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; however, application of 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 of 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 7 , and may be conducted at 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 1
Maximum Allowable Noise Levels (dBA)
for Receiving Land Use Categories
Day/Night 8
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 Table 1 during nighttime hours.
COMAR 26.02.03.02B. The noise regulations also address vibrations: “A person may not
7
“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
8
“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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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 (i.e., especially
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.
O. Invasive species
UMCES-AL Report recommendations 1-K, 5-G, 5-G.1, 5-H, 6-H, 6-I
An invasive species plan must be submitted 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 the power washing of water withdrawal equipment
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
lease 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, 7-B, 7-B.1, 7-B.3
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
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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
personnel must be capable of arriving at the site within 24 hours of the incident.
To support preparations and training by first responders and well pad staff for any
chemical emergencies, the UMCES-AL report recommended that lists of chemicals to be
used on site (including appropriate toxicological data, chemical characterizations,
Material Safety Data Sheets, and spill clean-up procedures) should be provided in permit
applications.
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 requirements for emergency response are
sufficient to enable first responders and well pad staff to appropriately respond to
emergencies involving chemicals. For this reason, the Departments do not agree that it is
necessary for information on all chemicals used on the site be provided to MDE with the
application for a permit to drill a well.
Operators shall prior to commencement of drilling, develop and implement an emergency
response plan, ensure local responders have appropriate training in the event of an
emergency, establish a way of informing local water companies promptly in the event of
spills or releases, and work with the local governing body in which the well is located to
verify that local responders have appropriate equipment to respond to an emergency at a
well.
Q. Site Security
UMCES-AL Report recommendations 7-C, 7-C.1. 7-C.2. 7-C.3, 10-F
The Departments accept the proposed site security recommendations intended to avoid
emergencies and would include practices such as:
1.
2.
Perimeter fencing, gates, locks and duplicate keys available to emergency
responders and regulatory personnel
Appropriate warning signs
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3.
Guarded access points, particularly during times of active operations
R. Closure and Reclamation both interim and final
UNCES-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. Reclamation
shall address all disturbed land, including the pad, access roads, ponds, pipelines and
ancillary equipment. The reclamation plan shall address (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.
Topsoil should be stockpiled during site development activities, covered during storage,
redistributed back onto agricultural land as part of the land reclamation process, and soil
compaction should be avoided at all times
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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. MDNR 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 has 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, fracking, 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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Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
(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.
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Discussion Draft dated May 13, 2013
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Section VIII – Miscellaneous Recommendations
A. Zoning
UMCES-AL Report recommendations 1-M
Zoning is a local matter over which the State has 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 Edwards, providing financial assurance for gas and oil drilling.
C. Forced Pooling
UMCES-AL Report recommendations 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.
38
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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.
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.
39
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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.
40
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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
Steven M. Bunker, director of Conservation Programs, Maryland Office of the Nature
Conservancy
John Fritts, president of the Savage River Watershed Association
Jeffrey Kupfer, senior advisor, Chevron Government Affairs
Clifford S. Mitchell, M.D., director, Environmental Health Bureau, DHMH
Dominick E. Murray, deputy secretary of the Maryland Department of Business and
Economic Development
Paul Roberts, Garrett County resident and co-owner of Deep Creek Cellars winery
Nick Weber, chair of the Mid-Atlantic Council of Trout Unlimited
Harry Weiss, Esq., partner at Ballard Spahr LLP
A-1
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
APPENDIX B – CONSULTATION WITH 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.
B-1
APPENDIX C – UMCES-AL REPORT
[Insert without transmittal letter as pdf after report is complete]
C-1
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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, leave 36.3% of the exploration area available for
surface development.
D-1
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
Subsurface Access Analysis
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-1
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
Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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 (MDNR) 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 utilizied;
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 accomodation areas or in
surrounding areas as a result of close proximity of infrastructure and people.
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Discussion Draft dated May 13, 2013
Preliminary; Do Not Quote or Cite
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. Infomation 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.
E-3
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