Marcellus Shale Safe Drilling Initiative Study Final Report

Marcellus Shale Safe Drilling Initiative Study Final Report
MARCELLUS SHALE SAFE DRILLING
INITIATIVE STUDY
PART III
FINAL REPORT
FINDINGS AND RECOMMENDATIONS
December 19, 2014
Prepared By:
Maryland Department of the Environment
Maryland Department of Natural Resources
Prepared For:
Martin O’Malley, Governor
State of Maryland
Thomas V. Mike Miller, Jr., Senate President
Maryland General Assembly
Michael E. Busch, House Speaker
Maryland General Assembly
Prepared pursuant to Executive Order 01.01.2011.11
Table of Contents
Table of Contents ........................................................................................................................................... i
Tables ............................................................................................................................................................ ii
Figures .......................................................................................................................................................... iii
Executive Summary................................................................................................................................... 1
Section I: The Initiative ............................................................................................................................. 3
Section II: Marcellus Shale Gas Development .......................................................................................... 5
A.
Shale Gas in Maryland................................................................................................................... 5
B.
Unconventional Gas Development and Production ..................................................................... 7
C.
Laws and Regulations Affecting Shale Gas Development ............................................................. 8
Section III: Work under the Initiative ...................................................................................................... 10
A.
Presentations and Briefings ........................................................................................................ 10
B.
Studies by Contractors ................................................................................................................ 11
C.
Studies by MDE and DNR ............................................................................................................ 12
D.
The Reports ................................................................................................................................. 13
Section IV: Principal Issues: Discussion and Findings.............................................................................. 17
A.
Air Pollution ................................................................................................................................ 17
B.
Methane Migration ..................................................................................................................... 25
C.
Noise ........................................................................................................................................... 27
D.
Soil Contamination, Groundwater Contamination and Surface Water Contamination ............. 30
E.
NORM and TENORM ................................................................................................................... 34
F.
Use and Disclosure of Chemicals ................................................................................................ 37
G.
Use of Fresh Water ..................................................................................................................... 47
H.
Greenhouse Gas Emissions ......................................................................................................... 49
I.
Impacts on Habitat and Natural Resources ................................................................................ 52
J.
Impacts of Traffic ........................................................................................................................ 55
K.
Community Impacts .................................................................................................................... 59
L.
Industrialization of Landscape .................................................................................................... 62
M. Influx of Workers......................................................................................................................... 67
N.
Availability of Housing................................................................................................................. 68
O.
Economic Impact: Gas Production .............................................................................................. 69
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P.
Economic Impact: Property Values ............................................................................................. 74
Q.
Economic impact: Tourism.......................................................................................................... 75
R.
Emergency Response Capacity ................................................................................................... 77
S.
Health Infrastructure Capacity .................................................................................................... 79
T.
Health Surveillance ..................................................................................................................... 82
U.
Waste and Wastewater Disposal ................................................................................................ 83
Section V: Information Gaps ................................................................................................................... 86
Section VI: Conclusions and Recommendations ..................................................................................... 88
References .............................................................................................................................................. 91
Appendix A: Members of the Advisory Commission .............................................................................. 97
Appendix B: Comments and Concerns.................................................................................................... 98
Appendix C: Best Practices.................................................................................................................... 100
Tables
Table 1. Sampling efforts. ........................................................................................................................... 19
Table 2. Hazard quotients calculated by McKenzie et al. ........................................................................... 21
Table 3. Typical Sound Reductions. ............................................................................................................ 28
Table 4. Maryland Maximum Allowable Noise Levels ................................................................................ 28
Table 5. Noise levels at distances ............................................................................................................... 29
Table 6. Setbacks......................................................................................................................................... 29
Table 7. Chemicals commonly used in hydraulic fracturing ....................................................................... 44
Table 8. EPA noise levels for heavy trucks .................................................................................................. 56
Table 9. Maryland maximum sound levels for heavy trucks ...................................................................... 57
Table 10. Land Use in Allegany and Garrett Counties................................................................................. 65
Table 11. Well and Well Pad Development Activity for Scenarios 1 and 2................................................. 65
Table 12. Economic and Fiscal Impacts for Allegany County – Scenario 1, 25% extraction ....................... 69
Table 13. Economic and Fiscal Impacts for Allegany County – Scenario 2, 75% Extraction ....................... 70
Table 14. Economic and Fiscal Impacts for Garrett County – Scenario 1, 25% Extraction ......................... 70
Table 15. Economic and Fiscal Impacts for Garrett County – Scenario 2, 75% Extraction ......................... 70
Table 16. Estimated Royalty Payments Made by Firms Extracting Gas in Allegany County ....................... 71
Table 17. Estimated Royalty Payments Made by Firms Extracting Gas in Garrett County ......................... 71
Table 18. Annual occupational fatality rate ................................................................................................ 80
Table 19. Annual nonfatal injuries rate....................................................................................................... 80
Table 20. Numbers of jobs in peak year ..................................................................................................... 80
Table 21. Number of fatalities in peak year ................................................................................................ 81
Table 22. Number of nonfatal injuries in peak year ................................................................................... 81
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Figures
Figure 1. Locations of the Marcellus Shale and Utica Shale ......................................................................... 5
Figure 2. Additional oil and gas basins in the Eastern United States ............................................................ 6
Figure 3. Average Hydraulic Fracturing Fluid Composition ........................................................................ 39
Figure 4. Garrett County 2010 Land Use / Land Cover ............................................................................... 62
Figure 5. Allegany County 2010 Land Use / Land Cover ............................................................................. 64
Figure 6. Employment Impacts in Allegany County .................................................................................... 73
Figure 7. Employment Impacts in Garrett County ...................................................................................... 73
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Executive Summary
Governor O’Malley’s Executive Order 01.01.2011.11 established the Marcellus Shale Safe Drilling
Initiative. Its purpose 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 Executive Order
tasks the Maryland Department of the Environment (MDE) and the Department of Natural Resources
(DNR), in consultation with an appointed Advisory Commission, with conducting a three-part study and
reporting findings and recommendations. The completed study includes:
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 possible gas production from the Marcellus Shale, was completed
in December 2011. In July 2014, the Departments released Part II of the study, Interim Final Best
Practices. This report represents Part III of the study, Findings and Recommendations.
This report synthesizes information from the work of the Departments and the Advisory Commission
over the past three and a half years and presents the joint findings and recommendations of MDE and
DNR, after consideration of the comments of the Advisory Commission. This work required a weighing of
competing interests, including the rights of property owners to realize the value of mineral rights
beneath their land, the positive impacts on the local economy, the threat to the existing economies that
are dependent on tourism and outdoor recreation, the possible climate change impacts, and protection
of public health, the environment, and the quality of life enjoyed by the people of Western Maryland.
Economic Impact
At the maximum estimated rate of extraction over a period of 10 years, Allegany County could
experience in the peak year as many as 908 new jobs, $1.8 million in tax revenues and $2.3 million in
severance tax revenues. In its peak year, Garrett County could gain as many as 2,425 new jobs, $3.6
million in tax revenues and $13.5 million in severance tax revenues. Royalty payment to the owners and
lessors of mineral rights could provide significant income. While these figures demonstrate an economic
benefit, the actual effect on the economy could be mixed.
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The amount of natural gas in Western Maryland is small compared to Pennsylvania’s and West Virginia’s
holdings, and the economic benefits, especially the jobs, are likely to last only a few years. It is not clear
whether the royalty payments would go to Marylanders, because in many cases the mineral rights were
severed from the surface rights decades ago. Resource extraction typically operates on a “boom and
bust” cycle, and jurisdictions that depend heavily on such industries often fail to diversify their
economies, making them especially vulnerable when that industry leaves.
The economy of Garrett County, more so than Allegany County, is dependent on tourism and outdoor
recreation, which could suffer during the active phases of gas development, even if no accidents or
incidents occur. A large portion of Garrett County’s revenue comes from real estate taxes on the land
around Deep Creek Lake, and studies have shown that property values can decline sharply if drilling
occurs nearby.
Public health, environmental and quality of life issues
Citizens of Western Maryland have raised legitimate questions about the likely impact of Marcellus
Shale gas development on public health, the environment and quality of life. This report evaluates the
key issues by explaining their significance, discussing the available information, and drawing a
conclusion about Maryland’s ability to manage the process.
There is no doubt that unconventional gas development in Western Maryland has the potential to harm
public health, the environment and natural resources. Best practices and rigorous monitoring,
inspection and enforcement can manage and reduce the risks. The Departments have proposed
innovative and flexible methods that are expected to: reduce air pollution; protect soil, groundwater
and surface water; properly regulate naturally occurring radioactive material mobilized by the drilling
operations; require disclosure of chemicals while protecting legitimate trade secrets; minimize adverse
impacts on habitat and natural resources; and address community concerns regarding noise, traffic,
damage to roads, and the industrialization of the landscape. Based on information compiled by the
Departments for the Advisory Commission, we believe that the influx of workers will be manageable,
that housing will be available, and that the emergency response and health care infrastructure will not
be overburdened.
Conclusion
It is the judgment of the Department of the Environment and the Department of Natural Resources that
provided all the recommended best practices are followed and the State is able to rigorously monitor
and enforce compliance, the risks of Marcellus Shale development can be managed to an acceptable
level. Some of the proposed best management practices have not been tested, and although we are
confident that they will reduce the risks, some risks will remain, as is the case with all industrial
activities. Best practices and rigorous monitoring, inspection and enforcement can reduce the risks to
acceptable levels, but cannot completely eliminate all the risks. Because knowledge and technology are
continuously advancing, it will be necessary to adaptively manage shale gas development by requiring
additional newly developed best management practices that provide improved protection for public
health and the environment.
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Section I: The Initiative
Governor O’Malley’s Executive Order 01.01.2011.11 established the Marcellus Shale Safe Drilling
Initiative. The Executive Order 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. The 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 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.
The Governor announced the membership of the Advisory Commission in July, 2011, and since its
inception the Commission held 35 meetings, all of which were open to the public. Most meetings were
in Allegany or Garrett Counties, but several were held in Hagerstown, Annapolis and Baltimore. The
Departments provided written information and briefings to the Advisory Commission on issues relating
to high volume hydraulic fracturing (HVHF). Speakers representing the scientific community, industry
and agencies from Maryland and other states presented information to the Advisory Commission and
the Departments. The Commissioners were able to visit active drilling sites. The Departments 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 Executive Order tasked 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 includes:
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.
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 for the second and third
reports.
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In Part II of the study, MDE entered into a Memorandum of Understanding with the University of
Maryland Center for Environmental Science, Appalachian Laboratory (UMCES-AL), to survey best
practices from several states and other sources, and to recommend a suite of best practices appropriate
for Maryland. The UMCES-AL recommendations were completed in February 2013 and made available
to the Advisory Commission and the public. A draft of the Departments’ report (“Draft Report”) was
made available for public comment on June 25, 2013. The recommendations in the Draft Report were
very similar to those in the UMCES-AL Report. Where a UMCES-AL recommendation was rejected or
modified, an explanation was provided. The comment period closed on September 10, 2013. More than
4,000 comments were received. Having considered all of the comments, including those of the Advisory
Commission, the Departments released Part II of the study, Interim Final Best Practices in July 2014.
This report represents PART III of the study- Findings and Recommendations.
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Section II: Marcellus Shale Gas Development
A.
Shale Gas in Maryland
Oil and gas develop from organic material that settled in ancient water bodies and became buried and
subjected to heat and pressure. Pressure, and heat through time may transform the organic material to
oil, wet gas (a mixture of methane and liquid hydrocarbons), and dry gas. Overly-mature source rock
contains mostly graphite and is probably not a good prospect for natural gas production.
Oil or gas may accumulate within permeable reservoirs beneath impermeable rock layers, from which it
can flow naturally or be pumped to the surface through wells. These are referred to as conventional oil
and gas reserves. Petroleum resources that cannot be exploited this way are termed “unconventional.”
In an unconventional reserve, the oil or gas is distributed throughout a relatively impermeable
formation rather than in pools and does not readily flow because it is trapped in the pore spaces of the
rock. Shale gas is an unconventional gas reserve.
There are two shale formations in Western Maryland that could produce oil, wet gas and dry gas: the
Marcellus and the deeper Utica. Although these formations have not been explored in Maryland, the
portions of the Marcellus Shale in Garrett County and western Allegany County are thought to contain
dry gas, while the portions of the Utica in Maryland are thought to be over-mature. Within Garrett
County and westernmost Allegany County the Marcellus is between 5,000 and 9,000 feet deep
(Brezinski) and the Utica shale is even deeper. The locations of the Marcellus Shale and Utica Shale are
shown in Figure 1 (Source, Marcellus Shale Coalition).
Figure 1. Locations of the Marcellus Shale and Utica Shale
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The Marcellus Shale is thought to have been the source rock for the natural gas in the Oriskany
Sandstone, which lies closely below the Marcellus in Western Maryland. Gas from the Oriskany was
extracted in Western Maryland beginning in the 1940’s and 50’s, and the depleted reservoir today is
used as a storage facility. Natural gas is injected back into the porous layers that once held natural gas,
and it is withdrawn to meet peak seasonal demand. The storage field is near the town of Accident, in
Garrett County.
There are other formations in Maryland that may contain oil and gas resources. Figure 2. Additional oil
and gas basins in the Eastern United States, Source: (USGS, 2012).
Figure 2. Additional oil and gas basins in the Eastern United States
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The United States Geological Survey has assessed the Taylorsville basin, but not the Gettysburg,
Culpeper or Delmarva basins in Maryland. The Marcellus Shale Safe Drilling Initiative addressed only the
Marcellus Shale in Western Maryland. The findings and conclusions of this report may not apply to
other basins.
B.
Unconventional Gas Development and Production
Prior to conducting any drilling activities in a region, oil and gas companies routinely use seismic
assessment surveys to target the best locations for drilling exploratory or production wells. Site
preparation involves clearing, leveling, and excavation at a well site to install the well pad, pits for the
storage of freshwater and wastes (if allowed), and any associated access roads.
After the site has been prepared and the drilling pad installed, one or more drill rigs are brought on site
to conduct well drilling. The bore hole is drilled vertically until the bit approaches the Marcellus Shale,
then the drill bit is turned gradually so that it enters the target formation, and drills horizontally through
the shale for distances that can extend for more than a mile. The hole is cased and cemented. Typically,
three levels of casing (surface, intermediate, and production) are used in a telescoping fashion. The
surface casing is run from the land surface to below the deepest freshwater layer. The intermediate
casing is run from the surface casing down to the target formation. The production casing is run from
the intermediate casing through the target formation. All casing strings are cemented in place to
stabilize the casing string and also seal the annular space between the casing and borehole to prevent
gas or fluid migration between geologic strata.
Once drilling, casing and cementing are complete, the casing in the horizontal section of the well is
perforated by a series of explosive charges that pierce the casing and cement and create small fractures
in the target formation in preparation for hydraulic fracturing. Fracturing fluid, usually made up of
about 90 to 95 percent water, chemical additives (about 0.5 to 2 percent), and about 8 to 9 percent
proppant -- usually sand that is mainly silicon dioxide (about 8 to 9 percent), are pumped into the well
at high pressure to further fracture the shale. Millions of gallons of fracing fluid are needed for each
well. As the fracturing fluid penetrates and enlarges the initial fractures created by the explosive
charges, the proppant fills the interstitial spaces of the created fractures and keeps them propped open
so that produced gas can flow into the well. Once fracturing is complete, some of the injected fracturing
fluids return to the surface as flowback. During the flowback period both hydraulic fracturing fluids and
other naturally occurring materials contained in the formation migrate up the borehole to the surface as
a result of the overlying geological pressure. Pipelines (gathering lines) that transfer the gas to
intrastate or interstate pipelines can be installed during this phase.
Once the well is connected to a pipeline, on site compressors may be used to provide the pressure
necessary to move the gas through the gathering lines. Offsite compressors are also required to
maintain necessary pressures to deliver gas to processing plants or intrastate or interstate pipelines. In
addition, produced gas may need additional processing to prevent condensation/crystallization of liquid
compounds in the gas gathering lines. This processing may occur both on-site, known as field
processing, and off-site at centralized processing plants.
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The well may produce gas for decades. At the end of its useful life, an expandable device or cement
must be placed in the well to prevent the movement of liquids and gas and the site must be reclaimed.
C.
Laws and Regulations Affecting Shale Gas Development
Federal laws and regulations
The oil and gas industry is subject to control under the Clean Air Act and the Clean Water Act and is
partially exempt from the Safe Drinking Water Act and the Resource Conservation and Recovery Act.
Under the Clean Air Act, EPA issued regulations in 2012 that set new source performance standards for
volatile organic compounds and sulfur dioxide; an air toxics standard for oil and natural gas production;
and an air toxics standard for natural gas transmission and storage. Some of these standards apply only
to larger sources; for example, the performance standards for storage tanks apply only if the tank has a
potential to emit 6 or more tons of volatile organic compounds a year.
Under the Clean Water Act, the direct discharge of wastewater from unconventional oil and gas
extraction is forbidden, while sending the wastewater to Publicly Owned Treatment Works (POTWs) is
subject to the general pretreatment regulations that forbid discharges that pass through or interfere
with the processes of POTWs. EPA has announced that it is revising its regulations for the oil and gas
extraction category and developing categorical pretreatment regulations. The proposal is expected by
the end of 2014.
The Safe Drinking Water Act (SDWA) allows EPA to regulate the subsurface emplacement of fluid for
storage or disposal; however, Congress excluded from regulation under the SDWA the underground
injection of fluids (other than diesel fuels) and propping agents for high volume hydraulic fracturing. In
2014, EPA issued guidance clarifying the meaning of “diesel fuels” and the scope of this exception.
The Resource Conservation and Recovery Act establishes a framework for identifying “hazardous
wastes” and setting standards for managing those wastes. Wastes from the exploration and production
of oil and gas are exempt from classification as hazardous wastes because they were thought to be
higher in volume and lower in toxicity than other wastes regulated as hazardous. These exempt wastes
include drilling fluids, produced water, and other wastes associated with the exploration, development,
or production of crude oil or natural gas. Some wastes generated at well sites are non-exempt, such as
waste solvents and unused fracturing fluids or acids that are discarded.
State laws and regulations
Maryland generally incorporates the federal rules as they relate to oil and gas exploration and
production. In addition, the laws relating to wetlands, stormwater, air permits to construct and permits
to operate apply. Maryland laws also regulate the issuance of permits for drilling oil and gas wells.
Under the Environment Article of the Maryland Code, Title 14, Subtitle 1, a permit is required for the
exploration, production, or underground storage of gas and oil; MDE is authorized to issue such permits.
No permits may be issued to drill for oil or gas in the waters of the Chesapeake Bay, any of its
tributaries, or in the Chesapeake Bay Critical Area. The Department is directed to deny the permit if it
determines that: the proposed drilling or well operation poses a substantial threat to public safety or a
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risk of significant adverse environmental impact; the operation will constitute a significant physical
hazard to a neighboring dwelling unit, school, church, hospital, commercial or industrial building, public
road, or other public or private property; or the operation will have a significant adverse effect on the
uses of a publicly owned park, forest or recreation area. The Department may place in a permit
conditions which the Department deems reasonable and appropriate to assure that the operation shall
fully comply with the requirements of the law, and provide for public safety and the protection of the
State's natural resources. Additional restrictions are placed on the awarding of any oil or natural gas
lease for production under lands or waters of the State (Natural Resources Article, Title 5, Subtitle 17).
The systems for nomination of areas for leasing must be established by the Board of Public Works;
however the Board has not adopted regulations governing leasing under State land or waters and no
leases have been approved.
Local laws and regulations
Local laws on oil and gas production on matters that are addressed by State law are likely to be
preempted by the State law. Zoning laws are not preempted. The Department must deny a permit if
the applicant failed to receive applicable permits or approvals for the operation from all local regulatory
units responsible for zoning (Environment Article, § 14-108(3)).
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Section III: Work under the Initiative
A.
Presentations and Briefings
Even before Governor O’Malley issued the Marcellus Shale Safe Drilling Initiative Executive Order, the
Departments had gathered and reviewed a considerable amount of information about unconventional
natural gas development. It was necessary to acquaint the Advisory Commission with the facts and the
issues, which was accomplished over time by sharing documents and through briefing papers and
presentations.
At the first meeting, the DNR Secretary discussed the interest the agency has about the longer-term
impact of gas exploration and development on the landscape and resources of Western Maryland,
particularly on land that the State owns or on which it has easements. Commissioners were encouraged
to learn from studies already done. The MDE Secretary gave a comprehensive overview of the Marcellus
Shale in Maryland, the opportunities and challenges, the existing regulatory programs, possible
economic impacts, and concerns about public health, safety, social and community well-being, and the
environment. Basic information about the natural gas industry and drilling, fracing, and transmission of
shale gas was also provided. The genesis of the Marcellus Shale Safe Drilling Initiative Executive Order
was explained, including the respective roles of the Departments and the Advisory Commission.
At subsequent meetings, the Departments provided briefing papers or presentations on a variety of
topics, including bonding; insurance; royalties; severance taxes; standards of liability; presumptions of
causation; trade secrets and chemical disclosure; Maryland’s permitting and regulatory programs,
including gas well permits, water appropriation, stormwater, erosion and sediment control, air pollution
and air monitoring; groundwater in Western Maryland; waste disposal; wastewater treatment and
disposal; naturally occurring radiation and technologically enhanced naturally occurring radiation;
traffic; road damage; greenhouse gas emissions and health care burdens.
The Commission heard presentations by industry experts Glen Benge and Michael Parker on American
Petroleum Institute Standards, industry practices generally, and drilling, casing and cementing,
specifically. Mr. Parker also provided feedback on the proposed best practices. Steve Moore and John
Arrell of ATK, an aerospace contractor, provided information on waterless fracing, using solid rocket fuel
to fracture the shale.
John J. Clementson, II, with the Engineering Division of the Maryland Public Service Commission gave a
presentation on the regulation of natural gas pipelines. John Quigley, a former Pennsylvania official
discussed his experience with comprehensive planning to protect forest land and on the concept of the
Comprehensive Gas Development Plan.
Keith Eshleman, Ph.D. and Andrew Elmore, Ph.D., of the University of Maryland Center for
Environmental Sciences Appalachian Laboratory (AL) collaborated on a comprehensive survey of best
practices and appeared at several meetings to provide briefings and answer questions. Representatives
of Towson University’s Regional Economic Studies Institute (RESI), including Daraius Irani, Ph.D., Jessica
Daniels Varsa, Jade Clayton and Susan Steward attended meetings to provide updates, give
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presentations, and answer questions on their economic analysis of gas development in Allegany and
Garrett Counties. Representatives of the Maryland Institute for Applied Environmental Health, including
Dr. Donald Milton, Dr. Amir Sapkota, Dr. Sacoby Wilson, Dr. Thurka Sangaramoorthy and Laura
Dalemarre and Meleah Boyle also attended meetings to give presentations on their health study and
answer questions.
The Department of Natural Resources undertook a natural resource analysis and expanded its stream
and groundwater baseline monitoring programs in Western Maryland. The Maryland Geological Survey
(MGS) gave presentations on the geology of Marcellus Shale, the phenomenon of methane in drinking
water wells, and fracture growth.
The Commission and representatives of the Departments were able to tour active drilling sites and
completed well pads. Members of the Commission shared information and documents.
When Memoranda of Understanding were developed for a survey of best practices, the economic
report, and the health report, the Commission was given an opportunity to comment on the work plan
and development scenarios and was briefed periodically on the progress of the studies. The Commission
was especially involved in the survey of best practices, with multiple presentations by the principal
investigator. The Commissioners were invited to comment on the work plan for the risk assessment and
to suggest risks to be evaluated.
Academicians and researchers gave presentations about their work: Anthony Ingraffea, Ph.D., Avner
Vengosh, Ph.D., Zacariah Hildenbrand, Ph.D. and Charles Yoe, Ph.D. The topics included: risk
assessments, risks of cement/casing failure, elevated levels of metals in groundwater in the vicinity of
gas wells, and contamination of drinking water by stray gas and other substances.
All meetings were open to the public, and if time allowed, the public was allowed to ask questions of
presenters and make comment. One evening meeting was held in Garrett County for the purpose of
hearing from the larger community. There was also an email address for submitting comments at any
time.
B.
Studies by Contractors
Five projects were undertaken by outside contractors engaged by the State: a survey of best practices, a
report on air monitoring data, a report on air emission control technology, an economic report, and a
public health report. Funding for these studies was provided by the State of Maryland.
Survey of Best Practices
The Maryland Department of the Environment engaged Keith N. Eshleman, Ph.D., of the University of
Maryland Center for Environmental Science – Appalachian Laboratory to survey best practices for shale
gas development and recommend a suite of practices that would be appropriate for Maryland. The
report was submitted to MDE in February 2013. MDE and DNR relied heavily on this report in
formulating their recommended best practices.
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Air Monitoring and Emission Controls (two studies)
The Air and Radiation Management Administration of MDE engaged Leidos, Inc., formerly SAIC, to
prepare two reports. The first project was to compile a review of air monitoring activities or special
studies to characterize ambient air quality impacts relevant to Marcellus Shale gas extraction and
production activities. Leidos also agreed to make recommendations regarding ambient air monitoring, if
Marcellus Shale gas production were to occur in Maryland. The report was issued in January 2014. The
second Leidos report reviewed regulations and manufacturer design requirements for emission control
equipment to be used during shale gas development and production. Leidos also made
recommendations for emission controls in the final report, which was also issued in January 2014.
Economic Report
The Maryland Department of the Environment engaged the Regional Economic Studies Institute of
Towson University to prepare an impact analysis of Marcellus Shale gas development. A report was
issued in May 2014 and a revised report was issued in September 2014. The report addressed economic
and fiscal impacts, housing impacts, tourism-related impacts, infrastructure and road impacts, and other
community impacts under three scenarios: no drilling, sufficient drilling to extract 25 percent of the
Maryland Marcellus Shale gas, and sufficient drilling to extract 75 percent of that gas. Where sufficient
data were available, the analysis was quantitative; otherwise, the impacts were qualitatively described.
Health Report
The Maryland Department of Health and Mental Hygiene (DHMH) entered into a Memorandum of
Understanding with MDE to coordinate a study of potential public health impacts of natural gas
development and production in the Marcellus Shale in Western Maryland. DHMH arranged for the
study to be performed by the University of Maryland School of Public Health, Institute for Applied
Environmental Health (MIAEH). The report, issued in July 2014, included a baseline health assessment, a
hazard evaluation for air quality, impacts related to flowback and produced water, noise, earthquakes,
social determinants of health, occupational health, and healthcare infrastructure. It also addressed
cumulative exposures and risks and made recommendations for public health responses to the potential
impacts.
C.
Studies by MDE and DNR
In addition to preparing the first two reports, issued in December 2011 and July 2014, the Departments
investigated specific issues and reported on the results to the Advisory Commission. DNR performed a
constraint analysis to estimate how much of the Marcellus Shale in Western Maryland could be
extracted by horizontally-drilled wells if the recommended location restrictions and setbacks that
prevent installation of well pads were adopted. The study was included in the second report as
Appendix D. DNR also addressed the impact of Marcellus Shale drilling on recreational and aesthetic
resources in Western Maryland. In November 2013, DNR hosted a participatory GIS workshop to
identify particular areas where recreational and aesthetic impacts would most likely intersect with shale
gas development activities, as described in Appendix E of the second report. A formal justification for
the aquatic habitat setback was presented in Appendix G of the second report. In cooperation with a
12
consultant, DNR prepared a report entitled The Case for Maryland’s Proposed Comprehensive Gas
Development Plan Program.
The Maryland Geological Survey performed a pilot study of methane in groundwater. Its report,
Dissolved-methane concentrations in well water in the Appalachian Plateau physiographic province of
Maryland, was issued as Administrative Report 14-02-01.
DNR’s Monitoring and Non-tidal Assessment Division (MANTA) developed and implemented a robust
baseline monitoring plan for surface waters in Western Maryland to locate and map sensitive species
and their habitats; describe the range of seasonal and annual fluctuations in water quality, physical
habitat condition, biological integrity and community composition; and document current thresholds for
signature water chemistry parameters. The monitoring stations were established in areas associated
with Marcellus Shale gas interests. MANTA also organized the Marcellus Shale Stream Monitoring
Coalition1 (MMC Program), a network of non-profit organizations, colleges, and interested citizens, with
a goal of collecting weekly water quality and biological data from surface waters to help characterize
baseline conditions and improve spatial coverage in the Marcellus Shale region. Seventy MMC
volunteers are monitoring 64 stream reaches in Garrett County with direct oversight by MANTA staff.
DNR developed a website, with an interactive map, that allows users to access the baseline surface
water data collected by MANTA staff and MMC.
MDE provided a brief report on methane and greenhouse gas emissions. This topic was specifically
mentioned in the Executive Order, and not addressed in any other report.
The Departments collaborated on a risk assessment. Dr. Charles Yoe of Notre Dame of Maryland
University advised the Departments and gave a presentation to the Advisory Commission about how risk
assessments are useful for making decisions under circumstances of uncertainty. Using available facts
and identifying knowledge gaps, the probability of the occurrence of the harm and the magnitude of the
harm can be estimated as high, medium or low. Risk is classified as acceptable, tolerable and
unacceptable. Classifying the risk involves value judgments and political judgments. When a risk is not
identified as acceptable, the question becomes whether there is a way to reduce the risk to make it
tolerable. The work plan and list of risks to be evaluated were discussed with the Advisory Commission
at public meetings. The draft risk assessment was released for public comment on October 3, 2014. The
comment period closed on November 17. The comments on the risk assessment have been considered
in preparing this report, even though the final risk assessment has not yet been released.
D.
The Reports
First Report
The Marcellus Shale Safe Drilling Initiative Study: Part I, was issued in December 2011. As directed by
the Executive Order, the Departments, in consultation with the Advisory Commission, addressed
revenue and liability. The summary of the revenue recommendations was stated as follows.
1
Maryland Department of Natural Resources, Stream Monitoring in the Marcellus Shale Region,
www.dnr.maryland.gov/streams/marcellus.asp (Last accessed Nov. 17, 2014).
13
A successful revenue structure to offset the costs of State activities will protect the local
economy, social well-being, public infrastructure, and natural environment; and
internalize the costs attributable to gas exploration and production to individual
operators where possible, and to the industry producing gas in Maryland where the
impact cannot be attributed to a specific operator, or for which there is no solvent
responsible entity. The Departments make the following recommendations regarding
revenue:
R-1
The General Assembly should impose a fee on gas leases to fund studies of the
issues set forth in the Executive Order.
R-2
The General Assembly should enact an appropriate State-level severance tax.
R-3
The severance tax revenue should be deposited into a Shale Gas Impact Fund to
be used for continuing regional monitoring and to address impacts of gas exploration
and production that cannot be attributed to a specific operator, or for which there is no
solvent responsible entity.
R-4
The General Assembly should amend the law that limits the amount of a
performance bond by deleting any reference to a dollar amount and directing MDE to
establish the proper amount of bond by regulation, based on a consideration of the
likely costs of complying with permit provisions, properly closing the well and
performing site reclamation. (This recommendations was acted on by the General
Assembly and is now in Maryland law, Chapter 568 of 2013.)
The discussion regarding liability was summarized as follows.
A liability system should be fair and equitable; promote the goals of environmental
sustainability, public health, and safety; and incentivize the prevention of harm. The
Departments make the following recommendations regarding liability:
L-1
The General Assembly should enact a law creating a rebuttable presumption that
certain damages occurring close in space and time to exploration and production activities are
caused by those activities, and an administrative process for requiring the permittee to
remediate the damage, pay compensation, or both. (This recommendations was acted on by
the General Assembly and is now in Maryland law, Chapter 703 of 2012.)
L-2
The General Assembly should enact a comprehensive Surface Owners Protection Act.
L-3
Community impacts should be addressed through mediation or by use of community
benefits agreements.
Second Report
To prepare The Marcellus Shale Safe Drilling Initiative Study: Part II: Interim Final Best Practices, the
Departments drew heavily from the UMCES-AL report, the expertise of its staff, research and
14
information presented at Advisory Commission meetings. The draft second report was released for
public comment in August 2013. More than 4,000 comments were received. The Interim Final Best
Practices report was finally released in July 2014. Appendix B contained the comments of the Advisory
Commission and Appendix C (147 pages) provided responses to the public comment. Changes had been
made to the draft in response to suggestions from the Commission and from the public.
This report was “Interim Final” because the Departments acknowledged that the best practice
recommendations could change as a result of the health report and the risk assessment, which had not
yet been completed. Notable features of the recommended best practices were:
A Comprehensive Gas Development Plan (CGDP). A prospective applicant for a permit to drill a gas well
must submit for approval a plan covering at least 5 years of activity, so that landscape level and
cumulative adverse impacts might be avoided or mitigated. An approved CGDP is a prerequisite for
filing an application for an individual well permit.
Location Restrictions and Setbacks. To protect people and the environment, the location of a well pad in
certain areas was prohibited. Where a well pad or other infrastructure is allowed, setbacks from
sensitive receptors are defined.
Engineering, Design and Environmental Controls and Standards. Minimum standards for construction,
sediment and erosion control, transportation, water withdrawal, storage and reuse, drilling, casing and
cement, chemical disclosure, air emissions, waste and wastewater treatment and disposal, protection
against light, noise, and invasive species, leak detection, site security and closure and reclamation were
established.
Application for a Permit to Drill. Following approval of the CGDP, a person may apply for a permit to
drill a well. The application must be consistent with the CGDP and include a plan for construction and
operation that meets or exceeds the enumerated controls and standards. The application must include
an environmental assessment and two years of monitoring in the vicinity of the well site to establish
background conditions.
As a result of the MIAEH health report and the Departments’ risk assessment, additional best practices
have been identified. They are:
1. Noise modeling must be included as part of the plan to comply with noise standards.
2. Noise reduction devices must be installed on all equipment at the drill site.
3. The number of truck trips to deliver material to the well pad and remove wastes and the impact
of the remaining trips must be reduced by the following methods, if they are practicable for the
specific site: establish a centralized water storage facility at a location that minimizes the use of
roads near homes or other occupied buildings for the truck transportation of water to the
centralized water storage facility; upgrade the roads to be used so that damage to the roadways
is minimized; transfer water from the centralized storage facility to the well pad using
aboveground temporary hoses or pipes; if it is demonstrated to be safe and effective and to
15
have a lesser impact than preparing and pressurizing the fracturing fluid at each well pad,
establish a centralized facility with all the equipment necessary for preparing and pressurizing
fracturing fluid with noise and air pollution controls that minimize impacts to people, and
deliver the fracturing fluid to the well pad using pipes; and if they are proven to be safe and
effective and have less impact, perform fracturing using alternatives to high volume waterbased fracturing fluid.
4. If feasible, one or more semi-permanent water supply access points with large capacity and
storage options should be established to decrease risks related to water withdrawals on
sensitive headwater streams and Use III and Tier II waters.
5. The capacity of the zero-discharge drill pad must be enlarged to contain at least the volume of a
25 year, 24 hour storm event.
6. At least two vacuum trucks will be required to be on standby at the site during drilling,
fracturing, and flowback so that any spills occurring during those stages, which could be of
significant volume, could be promptly removed from the pad.
7. The option to allow a variance of the 2,000 foot setback from a private drinking water well
based on the consent of the owner of the drinking water well should be eliminated.
8. Additional modeling for water withdrawal impact assessment in sensitive locations, such as Use
III and Tier II waters, will be required.
9. MDE and DNR will develop additional scientific guidance for monitoring and assessing potential
ecological impacts to sensitive streams as a result of water withdrawals.
10. Cement must be tested before use under conditions similar to those to be encountered
downhole.
11. Applicants for well permits will be required to disclose if they intend to use shaped charges
containing radioactive material such as depleted uranium.
12. Applicants will be required to estimate remaining methane emissions and report this
information to MDE. Once a trading program is available, MDE will require offsets.
Third Report
This report synthesizes information from the work of the Departments and the Advisory Commission
over the past three and a half years and presents the findings and recommendations of MDE and DNR.
It was released in draft on November 25, 2014, and discussed at the Advisory Commission’s meetings on
November 25 and December 8. Written comments were also received and considered before this
report was finalized.
16
Section IV: Principal Issues: Discussion and Findings
A.
Air Pollution
Background
Each stage of unconventional gas development has the potential to emit pollutants into the air. The
sources include road dust; on-road and off-road vehicle activity; off-road diesel-fueled equipment that
powers the drill rig, supplies the pressure for hydraulic fracturing, and generates electricity; gas escaping
during drilling; volatilization of organic compounds from drilling fluids, muds, cuttings and flowback;
releases of proppant, leakage and venting during flowback; flaring; methane leakage from valves, seals,
and gaskets; compressor engine exhaust; and pneumatic pumps and devices.
The pollutants emitted can be classed as:
Hazardous air pollutants (HAPs). Also known as toxic air pollutants, these substances are known or
suspected to cause cancer or other serious health effects, such as birth defects or reproductive effects.
The Clean Air Act currently lists 188 toxic air pollutants to be regulated by EPA. They are emitted from all
types of sources, including motor vehicles and stationary sources, such as manufacturing plants. EPA
regulates HAPs by setting performance standards for major industrial sources based on what the air
pollution control technology can achieve.
Volatile organic compounds (VOCs). This class includes a variety of chemicals that have high vapor
pressure and are emitted as gases from some solids or liquids. Some have short- and long-term adverse
health effects. Many VOCs are human-made chemicals that are used and produced in the manufacture
of paints, pharmaceuticals, and refrigerants. VOCs are often components of petroleum fuels, hydraulic
fluids, paint thinners, and dry cleaning agents. VOCs are common ground-water contaminants.
Concentrations of VOCs are consistently higher indoors than outdoors, regardless of whether the homes
are in rural areas or highly industrialized areas, possibly because so many household and office products
contain VOCs.
Criteria pollutants. Ozone, particulate matter, carbon monoxide, nitrogen oxides, sulfur dioxide, and
lead are called “criteria pollutants” because EPA sets the permissible levels in outside air on human
health-based or environmentally-based criteria. The permissible levels are called National Ambient Air
Quality Standards (NAAQS). Primary NAAQS are set to protect human health and secondary NAAQS are
set to prevent environmental and property damage. A geographic area with air quality that is cleaner
than the primary standard is called an "attainment" area; areas that do not meet the primary standard
are called "nonattainment" areas.
Greenhouse gases. These are gases which allow direct sunlight (relative shortwave energy) to reach the
Earth's surface unimpeded. As the shortwave energy (that in the visible and ultraviolet portion of the
spectra) heats the surface, longer-wave (infrared) energy (heat) is reradiated to the atmosphere.
Greenhouse gases absorb this energy, thereby allowing less heat to escape back to space, and 'trapping'
it in the lower atmosphere. Many greenhouse gases occur naturally in the atmosphere, such as carbon
17
dioxide, methane, water vapor, and nitrous oxide, while others are synthetic. NOAA, National Climate
Data Center, www.ncdc.noaa.gov/monitoring-references/faq/greenhouse-gases.phpH.
Silica. Silica is a compound made up of silicon and oxygen atoms. The chemical formula is SiO2. Silica
exists in two states: crystalline and noncrystalline (also called amorphous). There is no specific federal
ambient air quality standard for silica; it is addressed by the NAAQS for particulate matter. The controls
for PM are the same controls for crystalline silica. This means that for those crystalline silica sources
where PM is controlled, crystalline silica emissions are also reduced.
Ozone precursors. VOCs and nitrogen dioxide can combine in the presence of sunlight to produce
ground level ozone.
Data and Discussion
Leidos, Inc., (2014) under contract with MDE, compiled a review of air monitoring activities and special
studies that characterized ambient air quality impacts relevant to Marcellus Shale gas extraction and
production activities. The studies differed in which pollutants were measured, and sometimes failed to
identify what oil or gas activities were occurring at the time of measurement or the distance between
the operations and the monitoring sites.
Leidos summarized completed and ongoing sampling efforts for criteria pollutants, hazardous air
pollutants, and other metrics with regard to ambient monitoring off of well pads and outside fence lines
in a table, which appears here in modified form.
Study Area (Reference)
Star Shell Road (DRI 2011)
Shale Play
Barnett
Shale Creek (DRI 2011)
Arkansas (AR 2011)
Barnett
Fayetteville
Barnett Shale Gas Impacts
(Bunch 2014)
Mobile Measurement in
Barnett Shale
(Raghavendra et al. 2013)
Methane fluxes from
Barnett Shale (Lauvaux et
al. 2013)
Natural Gas Exploration in
Barnett Shale (Rich 2011
and Rich et al. 2013)
Barnett
Pennsylvania Long-Term
Study (PA DEP, 2013c)
Marcellus
Barnett
Barnett
Barnett
Emissions Sources
Well pad with two condensate tanks in
production phase
Compressor station
Six drilling sites, three hydraulic
fracturing sites, and four compressor
stations
All operations in both dry gas and rich
gas areas
401 wet gas production lease sites,
including wells, liquid storage tanks, and
associated equipment (500-2,000 feet)
Regional air quality downwind of Fort
Worth
39 sites (28 of which were within 2000
feet of at least one well, tank,
compressor or separator), fifty 24-hour
canister samples
Three sites: Fractionation plant,
compressor station, and in a populated
area downwind of a booster station and
ten wells
18
Sampling Period
April 16-May 13, 2010
April 20-May 13, 2010
November 2010 – June
2011 (measurement
periods only a few hours
at each site)
Focus on 2011
March-July 2012
March 2013
2008-2010
One year in 2012-2013
Study Area (Reference)
Southwest Pennsylvania
Short-Term Study (PA DEP
2010)
Northeast Pennsylvania
Short-Term Study (PA DEP
2011)
Northcentral Pennsylvania
Short-Term Study (PA DEP
2011)
WVU study of drilling and
construction (McCawley
2013)
PA Community Survey
(Steinzor 2013)
Fracturing in Greene
County, PA (Pekney 2013)
Impacts on Pittsburgh
Regional Air Quality
(Swarthout et al. 2012 and
Mitchell 2012)
Shale Play
Marcellus
Marcellus
Emissions Sources
Two compressor stations, condensate
tank farm, wastewater impoundment,
and background site
Hydraulic fracturing, producing well pad,
two compressor stations, and
background site
Two compressor stations, flaring well
site, and active well-drilling site
(background site from NE PA study)
Six sites: site preparation, vertical and
horizontal drilling, hydraulic fracturing,
and flowback
Residential areas near wells
Marcellus
Hydraulic fracturing over six wells
Marcellus
Regional air quality around 8500-km
area centered on Pittsburgh
Marcellus
Marcellus
Marcellus
2
Sampling Period
Five events in 2010, each
one week long
Five events in 2010, each
one week long
Four events in 2010, each
one week long
July 20-November 6, 2012
(longest sampling period
at one site 28 days)
34 canister samples (24hour)
Fourteen weeks in 2012
June 16-18, 2012
Table 1. Sampling efforts.
Source: Table 4 of Leidos 2014
Leidos focused on data collected in recent years because both the monitoring technology and
equipment and practices in the industry have improved. It noted that the Marcellus Shale in Maryland is
likely to contain dry gas, like much of the Barnett Shale. On the other hand, Western Maryland’s
meteorological patterns are expected to be more similar to the other Marcellus Shale areas.
In reviewing a report by Bunch (2014) of community-oriented concentrations of benzene, n-hexane,
toluene and xylenes from both wet gas and dry gas areas of the Barnett Shale by one hour and 24 hour
samples, Leidos noted, that the median measured concentrations were below the chronic health effects
levels for those chemicals by two orders of magnitude (100 times) or more. Wet gas and dry gas had
similar values for benzene, ethylbenzene, toluene and xylenes, but n-hexane concentrations were
slightly higher in the wet gas fields. The hourly measurements varied more than the 24-hour samples.
The health report by Maryland Institute of Applied Environmental Health (MIAEH)(2014) did not discuss
the Bunch report.
Leidos discusses a report by Raghavendra et al. (2013) of a survey of 401 lease sites (4,788 wells) across
four counties in the Barnett Shale region for methane and hydrogen sulfide. Hydrogen sulfide exceeded
the odor recognition threshold beyond the fence line at 5.5 percent of the lease sites. Methane
concentrations exceeded 3 ppm at 14.4 percent of the lease sites. MIAEH (2014) did not discuss the
report by Raghavendra et al.
McKenzie et al. (2012) published a report on ambient air monitoring in Garfield County, Colorado,
Human health risk assessment of air emissions from development of unconventional natural gas
resources, which was based on samples collected and analyzed by others. The Garfield County
Department of Public Health collected the following samples:
19
o
o
o
163 ambient air samples from a fixed monitoring station located among rural home sites,
ranches, and well pads, during both well development and production.
16 ambient air samples at each cardinal direction along 4 well pad perimeters while at least one
well was in the process of collecting flowback into collections tanks vented directly to the air
(i.e., uncontrolled emissions). The sampling points were 130 feet to 500 feet from the well pad
center. The samples were taken over a 24 to 27-hour interval, during which diesel engines were
also running, presumably contributing to the sample.
Background samples 0.33 miles to 1 mile from each of the 4 well pads
In addition, a natural gas operator contracted a consultant to collect eight 24-hour samples at each
cardinal direction at 350 feet and 500 feet from the well pad center during well completion activities at
one well pad. According to McKenzie et al. (2012), “Of the 12 wells on this pad, 8 were producing salable
natural gas; 1 had been drilled but not completed; 2 were being hydraulically fractured during daytime
hours, with ensuing uncontrolled flowback during nighttime hours; and 1 was on uncontrolled flowback
during nighttime hours” (p. 3).
MIAEH noted that “Results showed that concentrations of VOCs were significantly higher within 0.5
miles from the well pad (median benzene 2.6 μg/m3, range 0.9-69 μg/m3) compared to >0.5 miles from
well pads (median benzene 0.9 μg/m3, range 0.1-14 μg/m3). The corresponding values for hexane were
7.7 μg/m3 (range 1.7-255 μg/m3 and 4.0 μg/m3 (range 0.23-62 μg/m3)” (p. 29). Leidos (2014) reports
the maximum concentrations at the sampling points within 500 feet of the well pad center and noted
that the differences between those values and measured concentrations at the fixed station “illustrate
how significantly the distance from the well pad can influence the measurements.” Leidos noted that
“The measured concentrations of the 23 detected species [chemicals] at the fixed station were all below
levels where chronic health effects might be expected. “
Making certain assumptions about exposure, and using the data described above, McKenzie et al. (2012)
calculated the Hazard Quotient2 for residents less than or equal to ½ mile of well sites and residents
living greater than ½ mile from well sites. The chronic hazard quotient is related to an exposure lasting
for years, but less than a lifetime. The subchronic hazard quotient is related to shorter term exposures.
The specific exposure assumptions used by McKenzie et al. are included in Table 2. Hazard quotients
calculated by McKenzie et al. reflect the development expected in Garfield County, Colorado, which is
significantly more intense than what is predicted for Western Maryland.
2
Hazard quotient is “the ratio of the potential exposure to the substance and the level at which no adverse effects
are expected. If the Hazard Quotient is calculated to be less than 1, then no adverse health effects are expected as
a result of exposure. If the Hazard Quotient is greater than 1, then adverse health effects are possible. The Hazard
Quotient cannot be translated to a probability that adverse health effects will occur, and is unlikely to be
proportional to risk. It is especially important to note that a Hazard Quotient exceeding 1 does not necessarily
mean that adverse effects will occur.” EPA, Technology Transfer Network, National Air Toxics Assessment, Glossary
www.epa.gov/ttnatw01/nata/gloss.html (last accessed Nov. 18, 2014).
20
Residents Residents
≤1/2 mile >1/2 mile
Total chronic hazard quotient
(Based on 95%
Upper Confidence Limit of mean
concentration)
Total subchronic hazard quotient
(Based on 95%
Upper Confidence Limit of mean
concentration)
1
0.4
5
0.2
Assumptions about exposure
levels
20 month exposure to well
completions on two well pads
with 20 pads per well, followed
by 340 months of gas production
from these wells
20 month exposure to well
completions on two well pads
with 20 pads per well
Table 2. Hazard quotients calculated by McKenzie et al.
The exposure of residents > ½ mile from well pads was related to the concentrations of the 163 area
samples; while the exposure of residents ≤ ½ mile was based on the 24 well completion samples.
Cumulative cancer risks were calculated to be 10 in a million for residents living within ½ mile and 6 in a
million for residents living more than ½ mile of wells.3 These risks could also be expressed as 1 in
100,000 and 0.6 in 100,000. While this is not an official EPA definition, the EPA Office of Solid Waste
and Emergency Response, when communicating with the public about Superfund sites, defines an
acceptable exposure level or acceptable risk as follows: “This is a risk level (or range) that people can be
exposed to, including sensitive populations, without health problems. For carcinogens, the acceptable
risk range is between 10-4 (1 in 10,000) and 10-6 (1 in 1,000,000).”4 The cumulative cancer risks
calculated by McKenzie et al. fall within this range of acceptable risk.
Colborn et al. (2014) reported results of weekly sampling beginning November 2, 2010 through October
11, 2011, at a fixed monitoring site that was within 1 mile of 130 producing natural gas wells in Garfield
Colorado. The author reports that during the sampling period drilling and fracturing events occurred on
three different pads. The author identifies “the vertical well pad of interest” as containing 16 wells
drilled into Williams Fork Formation of the Mesa Verde Group at a total depth of approximately 8,300
feet (2530 km) in tight sands. The USGS (2003) reports that gas production in this formation is primarily
from fluvial channel sandstone reservoirs. The Williams Fork Formation contains coal deposits that are
thought to be the source for most of the gas. Leidos (2014) notes the distinction between this formation
and the Marcellus Shale.
According to Colborn et al., “Means, ranges, and standard deviations were presented for all chemicals
detected at least once. … Because of the exploratory nature of the study and the relatively small data
set, values for non-detects were not imputed, no data transformations were performed, and statistical
tests of significance were not conducted.” MIAEH noted that Colborn “reported the highest levels of
3
“A risk level of ‘N’ in a million implies a likelihood that up to ‘N’ people, out of one million equally exposed people
would contract cancer if exposed continuously (24 hours per day) to the specific concentration over 70 years (an
assumed lifetime). This would be in addition to those cancer cases that would normally occur in an unexposed
population of one million people. “ EPA, Technology Transfer Network, National Air Toxics Assessment, Glossary
www.epa.gov/ttnatw01/nata/gloss.html (last accessed Nov. 18, 2014)
4
EPA, Risk Communication, Attachment 6, Useful Terms and Definitions for Communicating Risk,
www.epa.gov/superfund/community/pdfs/toolkit/risk_communication-attachment6.pdf
21
non-methane hydrocarbons (NMHC) concentrations during the initial drilling phase. The methane
concentrations reported were particularly high ranging from 1600 to 5500 ppb (mean 2473 ppb), while
methylene chloride ranged from 2.7 to 1730 ppb (mean 206 ppb). The authors reported that the levels
of PAHs [polycyclic aromatic hydrocarbons] detected in this particular study were higher than the ones
that produced lower developmental and IQ scores in children in a separate study” (p. 29). Leidos (2014)
noted that Colborn attributed the high methylene chloride levels to the use of that substance as a
cleaning solvent on the pad and that elevated levels of methylene chloride were not found in two
Pennsylvania studies.
A report prepared for the West Virginia Department of Environmental Protection by McCawley (2013)
discussed data collected at seven drilling sites to determine the effectiveness of a 625 foot setback from
the center of a well pad. The pads were located in Brooke, Marion, and Wetzel Counties, West Virginia,
in areas where there the gas contains natural gas liquids. The study was designed to measure ambient
concentrations during pad site development, vertical drilling, horizontal drilling, hydraulic fracturing,
and flowback and completion. No information was available on what air pollution controls, if any, were
being used.
Detectable levels of dust and volatile organic compounds were found at 625 feet. Measured levels of
hydrocarbons were compared to the chronic Minimum Risk Level (MRL) below which no health effects
should occur if exposure at that level were to continue for a year or more. The measured exposure level
divided by the MRL is called the Hazard Quotient (HQ); if the measured value exceeds the MRL, that
number will be greater than 1.0. The author explained that “An exposure level exceeding the MRL
merely indicates that further evaluation of the exposure scenario and potentially exposed population
may be warranted, although the more often the MRL is exceeded and the greater the magnitude of the
value by which the MRL is exceeded, the greater the likelihood that an adverse health outcome will
occur” (p. 8).
One or all of the BTEX compounds (benzene, toluene, ethylbenzene and xylenes) were found at all drill
sites. Benzene concentrations greater than the MRL were measured at four of the seven sites; the HQs
varied from 1.3 to 28.3. Except for benzene, the HQ was 1.0 or less for all the measured hydrocarbons.
MIAEH (2014) observed that the concentrations of selected VOCs in West Virginia study varied
considerably and were higher than the McKenzie (2012) study in Colorado.
No data have been found on ambient levels of silica in communities near well pads where sand is used
as a proppant. The activities of transporting, moving, and refilling silica sand into and through sand
movers, along transfer belts, and into blender hoppers at the well site can release dusts containing silica
into the air. Recent work by the National Institute for Occupational Safety and Health (NIOSH) found
that some oil and gas workers are exposed to crystalline silica far in excess of permissible exposure
levels set by the Occupational Safety and Health Administration (OSHA). The federal agency issued a
Hazard Alert that recommended steps for reducing the amount of silica that is emitted into the air.
(OSHA 2012).
22
MIAEH (2014) also estimated yearly process-level emissions of particulate matter, NOx, and VOCs for
two drilling scenarios using a variety of assumptions. One of the assumptions was that there would be
no significant reductions in the emission rates from these processes after 2009, despite the fact that two
significant federal regulations were promulgated after 2009 that require reduced emission completions
and emission controls on large storage tanks. MIAEH calculated that during the peak production year of
the more aggressive drilling scenario, approximately 22 tons of fine particulate matter, 468 tons of NOx,
and 517 tons of VOCs would be emitted by all the unconventional natural gas development and
production-related activities in Garrett and Allegany Counties together. Roy et al. (2014) estimated that
process level emission rates related to drill rigs, hydraulic fracturing and truck traffic would decline
between 2009 and 2020 by 54 percent for NOx, 58 percent for fine particulate matter, and 62 percent
for VOCs.
MIAEH concluded that there is a high likelihood that changes in air quality related to unconventional gas
development will have a negative impact on public health in Garrett and Allegany Counties. This
conclusion was qualified, as were all MIAEH’s risk rankings: “Our assessments of potential health
impacts are not predictions that these effects will necessarily occur in Maryland, where regulation is
likely to be stricter than in some states where UNGDP is already underway. Rather, we provide
assessments of the impacts that could occur and that need to be addressed by preventive public health
measures if and when drilling is allowed” (p. xv).
In their Interim Final Best Practices Report (MDE and DNR, 2014a), the Departments identified
requirements that will reduce air pollution from Marcellus Shale gas development. Among these are
Reduced Emissions Completions (REC), limitations on flaring, use of ultra-low sulfur diesel fuel,
limitations on engine idling, and most importantly, top-down Best Available Technology (BAT) for the
control of air emissions. Top-down BAT means that the applicant will be required to consider all
available technology and implement BAT control technologies unless it can demonstrate that those
control technologies are not feasible, are cost-prohibitive or will not meaningfully reduce emissions
from that component or piece of equipment. While the amount of emission reduction for some control
technologies have not been established, in field measurements by Allen et al. (2013) REC was shown to
reduce methane emissions by 98 percent (compared to potential emissions). In its Background
Supplemental Technical Support Document for the Final New Source Performance Standards, (EPA,
2012). EPA estimated that REC could reduce the amount of VOCs released during hydraulic gas well
completion by 95 percent.
The Departments’ risk assessment (MDE and DNR, 2014b) ranked the risks posed by air pollution as low
or moderate, except for:
1. A high ranking (high probability, moderate consequence) for NOx, benzene and particulate
matter from fuel-burning pumps during hydraulic fracturing/well completion (more intensive
drilling scenario only);
2. A high ranking (high probability, moderate consequence) for methane, H2S, VOCs, natural gas
liquids and BTEX from flowback storage tanks in the hydraulic fracturing/well completion phase
(more intensive drilling scenario only);
23
3. Insufficient data to evaluate the risk of NOx, benzene, and dust/particulate matter from truck
trips during the drilling phase
4. Insufficient data to evaluate the risk of NOx, benzene, and particulate matter from combustion
during the hydraulic fracturing stage;
5. Insufficient data to evaluate the risk of dust/particulate matter from noncombustion sources
during the hydraulic fracturing stage (more intensive drilling scenario only); and
6. Insufficient data to evaluate the risk for NOx, benzene, and particulate matter from fuel burning
compressors during the production stage.
The hydraulic fracturing stage is of relatively short duration – approximately 5 days per well. During this
time, the pumps would be used to pressurize the fracing fluid. Under the more intensive drilling
scenario, this activity could occur for an average of 225 days per year over the 10-year drilling period;
however, it is likely to occur for approximately 30 days for any six-well pad.
The high ranking for methane, H2S, VOCs, natural gas liquids and BTEX from flowback storage tanks is
probably overly conservative because the Marcellus Shale gas in Maryland is expected to be dry. In
addition flowback must be placed in covered tanks and vented to a flare or other pollution reduction
device.
The terrain and meteorology of Western Maryland are such that pollutants can become trapped in
valleys. This “valley stagnation” may cause people in the entire valley to experience elevated
concentrations of air pollutants, because the trapped pollutants do not disperse readily. In this situation,
setback requirements will not result in the desired protection.
Conclusion
Air pollution from operations at the pad and from traffic is a concern. Implementation of the best
practices, especially top-down BAT and the storage of flowback in tanks with emission controls instead
of impoundments, should significantly reduce ambient levels of pollutants emanating from the pad area.
If monitoring does not confirm the effectiveness of these measures, additional controls may be
necessary. If the topography and prevailing wind directions indicate that valley stagnation may be a
concern, relocation of proposed well pads, additional controls and additional monitoring should be
considered before permits are issued.
Air emissions from vehicles are also a concern. If alternative means for moving water and wastes are
available, they should be investigated and required if appropriate. The Comprehensive Gas
Development Plan should identify routes that do not require heavy truck traffic on roads that are close
to homes and schools. Inspection of trucks for compliance with Maryland’s Diesel Emissions Control
Program should be scheduled to coincide with expected heavy truck traffic.
24
B.
Methane Migration
Background
Methane, the primary component of natural gas, is an odorless5, colorless gas with the chemical formula
CH4. Methane in its gaseous form is a simple asphyxiant, which in high concentrations may displace the
oxygen supply needed for breathing, especially in confined spaces. Decreased oxygen can cause
suffocation and loss of consciousness. It can also cause headache, dizziness, weakness, nausea,
vomiting, and loss of coordination (National Institutes of Health (NIH). NIH Tox Town - Methane.
http://toxtown.nlm.nih.gov/text_version/chemicals.php?id=92). Similar ecological concerns are
applicable to organisms inhabiting caves or other confined habitats where gaseous methane
concentrations may increase.
Methane present in drinking water does not affect taste or appearance, except that it can cause the
water to appear cloudy or produce effervescent gas bubbles. There is no evidence that ingestion of
methane in drinking water affects human health. (NIOSH).
Methane is extremely flammable and can form an explosive mixture with air at concentrations between
5 percent (lower explosive limit) and 15 percent (upper explosive limit). If methane enters a building,
either through contaminated well water or from other pathways, the concentration can build up in the
indoor air, creating a risk of fire or explosion and, in an extreme case, asphyxiation. The US Department
of the Interior, Office of Surface Mining, suggests that when the level of methane gas in the water is less
than 10 mg/L it is safe, but monitoring is required at 10 to 28 mg/L, and immediate action is needed
above 28 mg/L. (Eltschlager, 2001).
Methane is a powerful greenhouse gas. This is further discussed in another section of this report.
Gas wells are designed and constructed to carry the natural gas from the target formation to the surface
for sale and to isolate all the zones through which the well passes from each other and from the gas
well. The design includes concentric steel casing of decreasing diameter and cement to fill the spaces
between the concentric steel casings and between the outermost casing and the rock through which the
vertical borehole was drilled. If the well casing leaks, methane can escape from inside the well and,
because methane is buoyant, rise through the subsurface to the shallow groundwater or to the
atmosphere. In addition, if there are imperfections in the cement, gas from outside the gas well, for
example, from shallower, intermediate methane-bearing formations, can migrate through the
imperfections in the cement and upward. In either case, drinking water aquifers could be contaminated
by methane.
Data and Discussion
Studies have documented that some drinking water wells have been contaminated with gas from deep
reservoir rocks, including the Marcellus Shale. In contrast, a study in the Fayetteville Shale in Arkansas
found no methane contamination of groundwater (Kresse, 2012). In northeastern Pennsylvania, some
shallow wells were contaminated with Marcellus gas; the wells within 1 km of drilling sites were more
5
An odorant is added to natural gas before it enters the distribution system so leaks can be easily detected.
25
likely to be contaminated (Osborn, 2011; Jackson, 2013). It has been suggested that the likelihood of
stray methane contamination depends on both well integrity and local geology that may or may not
provide flow paths (Warner et al., 2013). Methane can enter groundwater in the absence of gas
development activities; sources of methane in groundwater include coal deposits and biological activity
in shallow buried sediments that contain organic material. There is consensus among most geologists
that, if there is a separation of at least 2,000 vertical feet between the target formation (the Marcellus
Shale, for example) and the drinking water aquifers (which generally occur at shallow depths) the
induced fracture cannot extend far enough to reach the drinking water aquifers. In summary, there are
two ways methane from the Marcellus Shale could enter drinking water aquifers: if the fractures
induced by hydraulic fracturing intersect a natural fracture or an improperly abandoned old gas well that
provides a pathway to drinking water aquifers, or if methane moves outside the Marcellus Shale well
along the vertical borehole because of casing or cement failure.
A minimum separation of 2,000 vertical feet between the top of the target formation and the lowest
drinking water aquifer will be required. As also indicated in the Interim Final Best Practices (MDE and
DNR, 2014a), the State will require that a prospective applicant for a well permit first secure MDE’s
approval of a Comprehensive Gas Development Plan, which must include a geological investigation by
the applicant of the area covered by the CGDP. The geological survey will investigate the location of all
gas wells (abandoned and existing), current water supply wells and springs, fracture-trace mapping,
orientation and location of all joints and fractures and other additional geologic information as required
by the State. Using this information, the gas wells can be located to avoid proximity to existing fractures
and other gas wells.
The Interim Final Best Practices Report recommended measures to assure good quality casing and
cement and testing methods to detect possible loss of integrity. Before commencing hydraulic
fracturing, the permittee must certify the sufficiency of the zonal isolation to MDE with supporting data
in the form of well logs, pressure test results, and other appropriate data.
The Departments had initially recommended a 1,000 foot setback from private residential drinking
water wells but, in response to comments on the draft report, changed the recommendation to require
a 2,000 foot setback from the edge of the drill pad to a private drinking water well, with a possibility of a
waiver to locate between 1,000 and 2,000 feet if the proposed gas well pad is not upgradient of the
private drinking water well and the water well owner consents. The reasons for the change and the
waiver related to surface spills and the movement of pollutants with the groundwater, not stray
methane. The Departments recognize that, because gaseous methane is buoyant and may move
through fissures in the ground, this variance is not appropriate to protect against stray methane. The
Departments now recommend a setback of 2,000 feet from the edge of the drill pad to a private
drinking water well, without an option for a variance. In light of the other best practices, the
Departments do not think a setback of one km is necessary.
If a drinking water well is contaminated with methane, there are methods for removing the methane
from the well water by venting the well or aerating the water. If the cause of the elevated methane is
corrected, methane levels in the drinking water may return to normal.
26
Conclusion
There is no single practice that will eliminate the risk of methane migration; rather, the Departments are
proposing a combination of setbacks; appropriate best practices; integrity testing; rigorous monitoring,
inspections and enforcement; timely identification and correction of problems; and mitigation if
methane contamination should occur.
C.
Noise6
Background
It is known that a person’s well-being can be affected by noise through loss of sleep, speech
interference, hearing impairment, and a variety of other psychological and physiological factors. The
equipment used at well pads during drilling and hydraulic fracturing can be very noisy.
Data and Discussion
The scale for measuring noise intensity is the decibel scale, with a weighted scale (dBA) to account for
relative loudness as perceived by the human ear. The noise scale is logarithmic, and an increase of 10
decibels represents a sound that is 10 times louder; however, humans do not perceive sound this way.
A change of 3 decibels is at the threshold of what a person can detect; a 5 decibel change is readily
noticeable; and the human ear perceives an increase of 10 dBA as a doubling of noise levels. (NYSDEC,
2011).
EPA has identified 55 decibels outdoors and 45 decibels indoors as noise levels that will not interfere
with normal activities or cause annoyance (EPA, 1978). These levels of noise permit spoken conversation
and other activities such as sleeping, working and recreation. Natural nighttime environmental noise
levels in rural areas are commonly estimated to be as low as 30 dBA, depending on weather conditions
and natural noise levels. The World Health Organization recommends that sound levels should not
exceed 30 dBA indoors for continuous noise and 45 dBA for intermittent noise. (WHO, 2000).
The combination of noises is not perceived as the sum of the noises. EPA explained the phenomenon
this way: “For example, if a sound of 70 dB is added to another sound of 70 dB, the total is only a 3decible increase (to 73 dB), not a doubling to 140 dB. Furthermore, if two sounds are of different levels,
the lower level adds less to the higher level. In other words, adding a 60 decibel sound to a 70 decibel
sound only increases the total sound pressure level less than one-half decibel” (EPA, 1978, p. 3).
The contribution of outdoor noise to indoor noise depends on several factors, including the construction
of the building and whether the windows are opened or closed. Generally dwellings are categorized as
those built in warm climates and those built in cold climates. EPA reports the following (EPA, 1978,
p.11):
6
Noise associated with traffic is addressed in Section J, below.
27
Typical Sound Level Reductions of Buildings
Windows Opened
Warm Climate
12 dB
Cold Climate
17 dB
Approximate National Average
15 dB
Windows Closed
24 dB
27 dB
26 dB
Table 3. Typical Sound Reductions.
EPA notes that indoor levels are often comparable to or higher than levels measured outdoors. Internal
noise sources such as appliances, radio and television, and heating and ventilating equipment contribute
to indoor noise (EPA, 1978).
Noise drops with distance. By application of the inverse square law and the logarithmic decibel scale, it
can be demonstrated that a sound level drops 6 dBA for each doubling of distance from the source.
(NYSDEC, 2011)
The Department of the Environment has promulgated standards for environmental noise; they can be
found in the Code of Maryland Regulations (COMAR) 26.02.03. The standards are goals expressed in
terms of equivalent A-weighted sound levels which are protective of the public health and welfare. With
certain exceptions, a person may not cause or permit noise levels which exceed those specified in Table
4.
Maximum Allowable Noise Levels (dBA) for Receiving Land Use Categories
Day/Night
Industrial
Commercial
Residential
Day (7 AM to 10 PM)
75
67
65
Night (10 PM to 7 AM)
75
62
55
Table 4. Maryland Maximum Allowable Noise Levels
The regulations permit more noise for construction and demolition site activities: 90 dBA during the
daytime hours, and the levels in Table 4, above, during nighttime hours. In addition, a person may not
cause a prominent discrete tone7 or periodic noise8 which exceeds a level which is 5 dBA lower than the
applicable level listed in the table. These noise standards do not apply to on-road vehicles. The noise
regulations also address vibrations: “A person may not cause or permit, beyond the property line of a
source, vibration of sufficient intensity to cause another person to be aware of the vibration by such
direct means as sensation of touch or visual observation of moving objects. The observer shall be
located at or within the property line of the receiving property when vibration determinations are
made.”
7
"Prominent discrete tone" means any sound which can be distinctly heard as a single pitch or a set of single
pitches. For the purposes of this regulation, a prominent discrete tone shall exist if the one-third octave band
sound pressure level in the band with the tone exceeds the arithmetic average of the sound pressure levels of the
2 contiguous one-third octave bands by 5 dB for center frequencies of 500 Hz and above and by 8 dB for center
frequencies between 160 and 400 Hz and by 15 dB for center frequencies less than or equal to 125 Hz. COMAR
26.03.02.01.
8
"Periodic noise" means noise possessing a repetitive on-and-off characteristic with a rapid rise to maximum and a
short decay not exceeding 2 seconds. Id.
28
Information on the noise expected to be produced by the activities used in each phase of horizontal
drilling and HVHF, and the evaluation of the noise at various distances from the source, are shown in
Table 5.
Phase
Construction of access road
Well pad preparation
Rotary Air Drilling
Horizontal Drilling
HVHF (20 Pumper trucks
operating at a sound level of
115 dBA)
50
89
84
79
76
dBA at a Distance of (Feet)
250
500
1,000
1,500
75
69
63
59
70
64
58
55
64
58
52
48
62
56
50
47
104
90
84
78
74
2,000
57
52
45
44
72
Table 5. Noise levels at distances
Source: Tables 6.54 through 6.58 (NYSDEC, 2011)
Minimum setback distances from the edge of disturbance of the well pad are:
Setback from edge of drill pad disturbance to
The boundary of the property on which the well is drilled
Any occupied building
Private drinking water well9
A church or a school
Distance in Feet
1,000
1,000
2,000
1,000
Table 6. Setbacks
Considering the information in Table 5 and Table 6, it appears that the Maryland residential noise
standards should be met during preparation of the well pad and operation of the drill rigs. During
hydraulic fracturing, however, and perhaps during other phases when electricity is generated on-site,
noise reduction will be necessary.
The Interim Final Best Practices Report (MDE and DNR, 2014a) identified practices that can reduce noise,
but it did not require reductions below the levels necessary to meet Maryland’s noise standards. The
best practices provide that the applicant must submit a plan for complying with the noise standards and
for verifying compliance after operations begin. If the applicant’s plan for complying with the noise
standards does not demonstrate that the noise standards will be met, the permit can mandate
additional noise reduction measures. If compliance with the noise standards is not verified after
operations begin, MDE could issue an administrative order requiring additional corrective action.
Various noise reduction measures can be taken to reduce the noise generated by equipment, or acoustic
barriers can be installed.
Conclusion
The best practices will ensure that noise levels will not exceed standards that are designed to prevent
the disruption of human activities or cause annoyance to the average person. To reduce noise further,
9
Because a private drinking water well is usually located close to the home it serves, this setback will increase the
distance between the well pad and the home.
29
however, additional steps will be required. First, noise modeling should be required for every drill site to
support and verify the permit applicant’s plan for complying with noise standards. Commercially
available software is capable of simulating the three-dimensional movement of sound, atmospheric and
other noise absorption features, and attenuation due to topography. (NYSDEC, 2011). Second, noise
reduction devices such as mufflers will be required for all equipment at the pad site to reduce noise to
the lowest practicable level.
D.
Soil Contamination, Groundwater Contamination10 and Surface Water Contamination
Background
Soil, groundwater and surface water could be contaminated by surface releases of fuel, additives,
drilling mud, hydraulic fracturing fluid, flowback, produced water, or condensate. Some of the potential
contaminants present health hazards if ingested or inhaled, or by dermal contact. It might be possible to
remove contaminated soil or remediate it in place while public access is restricted, if necessary. Besides
methane, shale gas development introduces the potential for groundwater contamination by other
fluids such as drilling fluid, hydraulic fracturing fluid, flowback water and production water. Both
flowback and production water tend to have very high salinities (Haluszczak et al., 2013), so in their
analysis of potential risk pathways, Krupnick et al. (2013) refer to groundwater contamination with brine
as “intrusion of saline formation water” (p. 20).
Contamination of an underground source of drinking water (USDW) with fracturing fluids or brine could
render the USDW unusable and could also impact aquatic life if and where the groundwater discharges
to surface water. Some chemicals that are human health hazards have been used in hydraulic
fracturing; for example, methanol, ethylene glycol, diesel fuel, and naphthalene (Waxman, 2011).
Flowback and formation waters typically contain elevated Cl, Br, Na, K, Ca, Mg, Sr, Ba, Ra, Fe, Mn, total
dissolved solids, and naturally occurring radioactive material (NORM) (Haluszczak et al., 2013).
Groundwater, once it is contaminated, is difficult to remediate, although sometimes it is possible to
pump and treat the water or use techniques like bioremediation to treat it in place. Public drinking
water systems may be able to treat the raw water to remove contaminants before distributing it. Pointof-entry and point-of-use drinking water treatment systems can be installed in homes to remove some
contaminants from the well water. Activated carbon filtration can effectively reduce the concentrations
of certain organic contaminants, lead, dissolved radon, and other substances. Mechanical filters can
remove particulate matter that contributes to turbidity. No one treatment system manages all
contaminants equally well, and the systems must be properly maintained to be effective.
Vehicular accidents involving trucks transporting muds, chemical additives or wastes could result in the
release of vehicle fluids (fuel, antifreeze, etc.) or the cargo if the tank trucks or containers are
compromised or rupture. If materials are spilled at the pad and are not contained, they could run off
and contaminate soil, groundwater and surface water. During early stages of drilling, before the surface
casing is installed, the drill bit passes through drinking water aquifers. During this activity, there is a
possibility that turbidity will increase in drinking water aquifers, as well as the possibility that drilling
10
Methane contamination is covered in Section B, above.
30
mud or other drilling aids will enter the drinking water aquifers. There is also the possibility of
subsurface contamination by saline fluids such as fracturing fluids, flowback, and production water.
These will be considered in turn.
Data and Discussion
Surface spills.
Vehicular accidents
If the contaminated soil is not removed, or if material is not cleaned up in a timely manner before it
infiltrates into the ground or runs off to surface water, the spilled material could cause contamination of
any of these media (soil, groundwater, and surface water). Transportation incidents involving hazardous
materials are relatively rare; using data from the federal Pipeline and Hazardous Materials Safety
Administration, Maryland’s risk assessment calculated the probability that a single trip would result in
an incident as 0.005 percent. (MDE and DNR, 2014b, p. 6). This is incidence data; not every incident
results in a release to the environment. Applying this rate to shipments of chemicals used as drilling
additives or fracturing additives leads to a prediction of fewer than 2 incidents involving additives in the
course of delivering additives for all 450 wells over 10 years of the more intensive drilling scenario.
Applying this incident rate to the number of truck trips to transport waste material off-site predicts
approximately 8 incidents, but the actual number of trips is likely to be lower, because the risk
assessment assumed that all flowback and produced water would be sent by truck for disposal. Best
practices require that, unless the operator can demonstrate that it is impracticable to do so, at least 90
percent of the flowback and produced water must be recycled and reused on site. Waste shipments will
be tracked to confirm that the entire amount was delivered to a proper treatment or disposal facility.
Releases at the well pad
The pad is the center of activity during drilling and high volume hydraulic fracturing. Not only are the
drill rig and vertical borehole there, but the pad is also the site for storing fuel and chemicals, handling
drilling mud and cuttings, mixing and pressurizing hydraulic fracturing fluid, mixing and pumping the
cement, and handling flowback and produced water. Pollutants released on the pad could enter the
environment by infiltrating through the pad, running off the pad, or being washed from the pad.
As far as we have been able to determine, a comprehensive study of the causes of spills has not been
done; however, it appears that releases at the well pad occur in any of several ways: operator error,
failure of valves, hoses or pipes, tank failures, blowouts, or incidents involving firefighting. In some
reported cases, the spilled material was not contained on the pad or was washed from the pad by
precipitation or by firefighters.
The best management practices address these possibilities as follows. No discharge of potentially
contaminated stormwater or pollutants from the pad shall be allowed. Drill pads must be underlain with
a synthetic liner with a maximum hydraulic conductivity of 10-7 centimeters per second and the liner
must be protected by decking material. Spills on the pad must be cleaned up as soon as practicable and
the waste material properly disposed of in accordance with law. The drill pad must be surrounded by an
31
impermeable berm such that the pad can contain at least the volume of a 25 year, 24 hour storm11. The
berm may be made impermeable by extension of the liner. Collected stormwater may be used for
hydraulic fracturing, but prior to use, it must be stored in tanks and not in a pit or pond. In addition, the
design must allow for the transfer of stormwater and other liquids that collect on the pad to storage
tanks on the pad or to trucks that can safely transport the liquid for proper disposal. The collection of
stormwater and other liquids may cease only when all potential pollutants have been removed from the
pad and appropriate, approved stormwater management can be implemented. Tanks and containers
must 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.
A three acre pad capable of containing the 25 year, 24 hour precipitation event of 4.5 inches would have
containment capacity of over 122,000 gallons. Few reported spills have been that large. During the
processing of large volumes of material, there are workers at the site, so a significant spill would not go
unnoticed. As an additional precaution, however, Maryland will require that at least two vacuum trucks
should be on standby at the site during drilling, fracturing, and flowback so that any spills occurring
during those stages, which could be of significant volume, could be promptly removed from the pad.
The probability of a well blowout is low as they rarely occur (approximately 1 well blowout per 1,000
wells). Implementation of the best practices, especially redundant blow out protection mechanisms and
frequent testing, should further reduce the potential for a well blowout to occur. When a blowout
occurs, material may be ejected high into the air and it may or may not fall directly on the pad. It is likely
that the well pad could contain material that falls on it. Material that falls away from the pad would
have to be cleaned up. Setbacks will reduce the chance that material that falls off the pad will impact
surface water or ground water before spill cleanup and emergency response.
Spill Prevention, Control and Countermeasures Plans (SPCC Plans) are intended to prevent any discharge
of oil and other hazardous substances. Spill cleanup and emergency response plans are intended to
address spills or other releases after they occur. The Departments identify as a best practice that
facilities develop plans for preventing the spills of oil and hazardous substances, using drip pans and
secondary containment structures to contain spills, conducting periodic inspections, using signs and
labels, having appropriate personal protective equipment and appropriate spill response equipment at
the facility, training employees and contractors, and establishing a communications plan. In addition,
the operator shall identify specially trained and equipped personnel who could respond to a well
blowout, fire, or other incident that personnel at the site cannot manage. These specially trained and
equipped personnel must be capable of arriving at the site within 24 hours of the incident.
11
This is a more severe storm than the 10 year, 24 hour storm described in the Interim Final Best Practices Report.
According to NOAA’s National Weather Service, the 25 year, 24 hour storm in Oakland is 4.5 inches (90 %
confidence 4.11 to 4.89);in Friendsville 4.32 (3.94 to 4.69); in Grantsville 4.59 (4.15 to 5.05); in Frostburg 4.54 (4.12
to 4.96); and in Cumberland 4.43 (4.06 to 4.78). National Weather Service, Hydrometeorological Design Studies
Center Precipitation Frequency Data Center, http://hdsc.nws.noaa.gov/hdsc/pfds/.
32
Operators shall, prior to commencement of drilling, develop and implement an emergency response
plan, establish a way of informing local water companies promptly in the event of spills or releases, and
work with the governing body of the local jurisdiction in which the well is located to verify that local
responders have appropriate equipment and training to respond to an emergency at a well. This should
reduce the likelihood that inappropriate methods will be used that will result in washing the
contaminants from the well pad.
Drilling through drinking water aquifers
Drinking water aquifers in Garrett and western Allegany Counties lie relatively near the surface; saline
water aquifers are present at greater depth. Surface casing must be installed and cemented in the gas
well to isolate the wellbore from the surrounding earth to a depth of at least 100 feet below the deepest
fresh water aquifer. Until this barrier is installed, however, the drilling can cause increased turbidity in
the aquifer that may show up in nearby wells. This can also occur when new drinking water wells are
drilled, and usually subsides within a short time. The drilling mud is weighted to apply pressure and
prevent fluids from entering the borehole. Some of the drilling mud may enter drinking water aquifers if
the pressure is too great. For this reason, the best practices require that only additives that the
manufacturer warrants have been certified under NSF/ANSI Standard 60, Certification for Drinking
Water Treatment Chemicals – Health Effects, may be used when drilling through fresh water aquifers.
Contamination by other saline fluids
Contamination of a fresh water USDW by hydraulic fracturing fluid, saline formation flowback, formation
water or methane should be impossible if surface casing is properly installed – with the casing set to an
appropriate depth, and the casing and cement functioning properly. Adherence to the drilling, casing
and cementing plan, as well as integrity testing will be a condition of the permit. Best practices will
require that, before commencing hydraulic fracturing, the permittee must certify the sufficiency of the
zonal isolation to MDE with supporting data in the form of well logs, pressure test results, and other
appropriate data. The well is pressurized only during the hydraulic fracturing stage, and therefore
releases of hydraulic fracturing fluid through casing or cement failure is unlikely.
Several authors report that they found no evidence of contamination of drinking water with brine
(Osborn et al., 2011; Jackson et al., 2013). In a recent report investigating the mechanisms by which
human activity could cause methane gas contamination to occur in drinking water wells, the authors
noted that samples with higher levels of thermogenic gas did not also exhibit higher chloride levels,
suggesting that the thermogenic hydrocarbon gas had separated from the brine and migrated in the gas
phase. For other samples where gas and brine levels did correlate, they concluded that the presence of
gas and chloride was natural and possibly a result of tectonically driven migration over geological time
of gas-rich brine from an underlying source formation or gas-bearing formation of intermediate depth
(Darrah et al., 2014). Because brine is so dense, it is not likely to migrate upward through
casing/cementing failures without significant induced pressure. Many gas shales, including most of the
Marcellus, are slightly to moderately overpressured, but once gas is produced, the formation pressure
drops rapidly to hydrostatic and below, and the preferred flow direction of gas and formation brines is
along the pressure gradient toward the wellbore (Personal Communication, Daniel Soeder, U.S.
33
Department of Energy, National Energy Technology Laboratory, November 5, 2014). Once gas is being
produced, there is nothing to drive fluids along other paths to the surface.
Conclusion
The likelihood of a transportation-related incident that will result in the release of significant amounts of
hazardous materials is low. If a spill occurs because of a transportation-related incident but is cleaned up
in accordance with law, the risk to groundwater is low, and the risk to surface water is low unless the
spill flows directly into surface water. If a spill occurs directly into surface water upstream of a public
drinking water intake, there could be an interruption to providing safe drinking water to the public.
The likelihood of soil, groundwater or surface water contamination from releases at the well site is low
because of the requirement that the pad be able to contain a very large volume and the implementation
of a spill prevention and response plan. Similarly, the risk of contamination of a drinking water aquifer
by hazardous materials during drilling or because of faulty casing and cement is low.
E.
NORM and TENORM
Background
Much of the petroleum in the earth's crust was created at the site of ancients seas by the decay of sea
life. As a result, oil and gas often occur in rock formations that contain brine (salt water). Radionuclides,
along with other minerals, are dissolved in the brine. The Marcellus Shale formed about 390 million
years ago from sediment and organic matter that settled in a shallow sea. The shale, like virtually all
environmental media, contains radioactive elements, including uranium and thorium. A concise
explanation was provided in a USGS paper from 2013:
Radium (Ra) is a naturally occurring radioactive material (NORM) that is present as a
component of the Marcellus Shale and is produced from the radioactive decay of high
concentrations of uranium and thorium found naturally within black shales. Uranium is
poorly soluble in water under the anoxic (oxygen-poor) conditions typical of black
shales, but radium is readily dissolved and transported. Although two of the radium
isotopes (223Ra and 224Ra) have short half-lives (a few days), the other two isotopes,
226Ra and 228Ra, have 1,622 and 5.75 year half-lives, respectively; if dispersed in the
environment, these isotopes will persist for long periods of time. Chemically, radium
behaves similarly to calcium (Ca), strontium (Sr), and barium (Ba). Radium can readily
precipitate along with salts of Ca, Sr, and Ba in groundwater or produced brines having
high total dissolved solids to form scale in or on drilling equipment or in on-site storage
tanks or brine pits.[12] The scale precipitate is rich in radium, and that may emit radiation
to those working near such equipment over time. The scale may eventually be removed
from the pipe and then is added to the waste stream from drilling that must go to a
landfill or can be dispersed to the local soil. Leachates from these materials may contain
radium that may eventually reach the local water table or run off to the local watershed.
12
This concentrated material is referred to as technologically enhance naturally occurring radioactive material.
34
The concentrations of NORM present in black shale drill cuttings, drilling mud, scale and
sludge build-ups, fluids from spills, treatment residuals, and other waste products may
be greater than background environmental levels. Disposal of these waste products onsite or in landfill burial sites will require assessments of both gamma radiation emissions
and radionuclide concentrations in solids and liquids. Dispersal of radium into soils may
have several effects in addition to the potential increase in gamma radiation exposures
and the potential for leaching into water resources. The 226Ra emits radon gas as a
decay product; structures built on the soil that contains 226Ra-bearing waste may have
high levels of indoor-air radon that require monitoring due to this type of exposure.
Plants may also take up the 226Ra from soil. Recently (2013), the Commonwealth of
Pennsylvania has initiated a study of the radioactivity of the Marcellus Shale through all
aspects of the gas drilling, extraction, and waste disposal. (Citations and a reference to a
figure omitted.)
EPA describes the risks of radium as follows (EPA, Radiation Protection, Radium
http://www.epa.gov/radiation/radionuclides/radium.html#properties:
Radium emits several different kinds of radiation, in particular, alpha13 and gamma14
radiation. Alpha radiation is only a concern if radium is taken into the body through
inhalation or ingestion. Gamma radiation, or rays, can expose individual even at a
distance. As a result, radium on the ground, for example, can expose individuals
externally to gamma rays or be inhaled or ingested with contaminated food or water.
The greatest health risk from radium in the environment, however, is actually its decay
product radon, which can collect in buildings.
Most radium that is swallowed (about 80%) promptly leaves the body through the feces.
The other 20% enters the bloodstream and accumulates preferentially in the bones.
Some of this radium is excreted through the feces and urine over a long time. However,
a portion will remain in the bones throughout the person's lifetime.
Long-term exposure to radium increases the risk of developing several diseases. Inhaled
or ingested radium increases the risk of developing such diseases as lymphoma, bone
cancer, and diseases that affect the formation of blood, such as leukemia and aplastic
anemia. These effects usually take years to develop. External exposure to radium's
gamma radiation increases the risk of cancer to varying degrees in all tissues and organs.
13
An alpha particle is “a positively charged particle made up of two neutrons and two protons emitted by certain
radioactive nuclei. Alpha particles can be stopped by thin layers of light materials, such as a sheet of paper, and
pose no direct or external radiation threat; however, they can pose a serious health threat if ingested or inhaled”
(EPA, Radiation Protection, Radiation Glossary, http://www.epa.gov/radiation/glossary/index.html)
14
Gamma rays are “high-energy electromagnetic radiation emitted by certain radionuclides when their nuclei
transition from a higher to a lower energy state. These rays have high energy and a short wave length. All gamma
rays emitted from a given isotope have the same energy, a characteristic that enables scientists to identify which
gamma emitters are present in a sample. Gamma rays are very similar to x-rays” (EPA, Radiation Protection,
Radiation Glossary, http://www.epa.gov/radiation/glossary/index.html).
35
Radon is an odorless, colorless radioactive gas. Radon can exist in different isotopic forms (having
different numbers of neutrons in the nucleus). Radon decays rapidly; its most stable isotope is Radon222, which has a half-life of 3.8 days; that is, half its radioactive atoms will decay every 3.8 days. As
radon itself decays, it produces new radioactive daughter products. Unlike the gaseous radon itself,
radon’s daughter products bond with other elements in solids or may be dissolved in solutions. Radon
and its daughters present a risk of lung cancer.
Radioactive materials must be managed properly so that persons are not exposed to unsafe levels of
radioactivity. The management must address the materials from the time they are generated to the
time they are properly disposed of.
Data and Discussion
In an EPA document last updated in 2012, EPA noted that NORM and technologically enhanced naturally
occurring radioactive material (TENORM) from oil and gas development are managed in several ways.
Produced waters are generally reinjected into deep wells. Sludges containing elevated TENORM are
dewatered and held in storage tanks for later disposal. Pipes contaminated with scale are cleaned at
pipe yards either by sandblasting them with high pressure water or by scraping out the scale with a
rotating drill bit. The removed scale is then placed in drums and stored for later disposal. Contaminated
equipment may be cleaned and reused by the petroleum industry; disposed; or, if radiation levels are
sufficiently reduced, sold for recycle. If equipment cannot be further decontaminated to acceptable
levels, it is sent to a licensed landfill (EPA, Radiation Protection, Oil and Gas Production Wastes,
www.epa.gov/radiation/tenorm/oilandgas.html).
Produced waters contain levels of radium and its decay products, but the concentrations vary from site
to site. EPA identifies the range for produced water as 0.1 picocuries per liter (pCi/L) to 9,000 pCi/L (EPA,
Radiation Protection, Oil and Gas Production Wastes, www.epa.gov/radiation/tenorm/oilandgas.html).
The Pennsylvania Department of Environmental Protection has undertaken a study of NORM in material
associated with oil and gas development. According to PA DEP, the study will “analyze the radioactivity
levels in flowback waters, treatment solids and drill cuttings, as well as issues with transportation,
storage and disposal of drilling wastes, the levels of radon in natural gas, and potential exposure to
workers and the public” (Oil and Gas Related Topics: Radiation Protection,
www.portal.state.pa.us/portal/server.pt/community/oil___gas_related_topics/20349/radiation_protect
ion/986697). The samples have been analyzed and once data analysis, report preparation and review
are completed, a final report is to be released, probably by the end of 2014.
Adgate et al. (2014) report that evidence suggested that wastewater is more effectively treated onsite
rather than at publicly owned treatment plants, which may not be able to provide sufficient treatment
for this wastewater. Maryland has decided not to allow the treatment of flowback or produced water at
publicly owned treatment plants, at least until EPA has developed pretreatment regulations. Even with
pretreatment, because of the elevated levels of salts, it may not be feasible to treat this wastewater at
any facility that discharges to fresh water. A large portion of flowback and produced water are now
recycled, either on site or at a central facility. The water is used to hydraulically fracture additional wells,
and the solid residue is dewatered and disposed of in a licensed landfill.
36
The Interim Final Best Practices Report (MDE and DNR, 2014b) identified steps to address radioactive
wastes: “Cuttings, flowback, produced water, residue from treatment of flowback and produced water,
and any equipment where scaling or sludge is likely to occur shall be tested for radioactivity and
disposed of in accordance with law” (p. 50). Some have expressed concern that the methods used to
detect radiation are inadequate to quantify the radiation in hydraulic fracturing wastes. EPA (2014)
recently released a white paper entitled “Development of Rapid Radiochemical Method for Gross Alpha
and Gross Beta Activity Concentration in Flowback and Produced Waters from Hydraulic Fracturing
Operations.” This updated method can analyze gross alpha and gross beta activity within about 24 hours
after the sample is received at the laboratory. Gamma radiation is measurable by a large variety of
devices that could easily be used at the well pad. If elevated levels of radiation are detected, additional
investigation can be done to identify the specific radioactive elements.
Unlike some states, Maryland has not established a radiation limit for wastes sent to municipal waste
landfills for disposal, nor are such landfills uniformly required to test incoming wastes for radioactivity.
Such landfills are, however, lined with leachate collection systems and groundwater monitoring. Work is
underway to develop regulations to address these issues in advance of any Marcellus Shale drilling in
Maryland.
Before a well can be hydraulically fractured, the casing and cement in the target formation must be
perforated and an initial entry must be made into the formation. This is accomplished in stages along
the horizontal borehole by using a perforating gun that contains several shaped charges -- explosive
devices that can be directed to create a perforation tunnel in the desired direction. These small devices
are inserted into the well and set off from the surface. It has been noted that patents exist for shaped
charges that contain depleted uranium. The Departments have not been able to confirm that such
devices are being used anywhere in the United States. Applicants for well permits will be required to
disclose if they intend to use shaped charges containing depleted uranium. The Departments will require
monitoring to identify any radiation risk and require proper handling and disposal of radioactive
materials.
Conclusion
Sufficient controls are, or will be, in place to assure proper management of any NORM and TENORM
that would be generated if Marcellus Shale drilling is allowed in Maryland.
F.
Use and Disclosure of Chemicals
Background
Quantities of chemicals are brought to the drill site and used there. Spills or other releases of these
chemicals at the surface are of concern to the community. In addition, chemicals are added to drilling
fluid and hydraulic fracturing fluid. The identity of chemical additives to drilling fluids and hydraulic
fracturing fluids is of particular concern because these chemicals are used underground where, if
appropriate precautions are not taken, the chemicals could enter underground sources of drinking
water. At the federal level, the Safe Drinking Water Act (SDWA) allows EPA to regulate the subsurface
emplacement of fluid; however, Congress excluded from regulation under the SDWA the underground
37
injection of fluids (other than diesel fuels) and propping agents for high volume hydraulic fracturing.
Many oil and gas companies voluntarily disclose the chemicals they use in hydraulic fracturing, although
the specific identity of some chemicals are withheld because the companies that market them claim that
the chemical or the formulation is confidential commercial information, often referred to as a trade
secret.
Other federal and State laws do require the disclosure of information about hazardous chemicals to
workers, consumers, and local and state emergency response authorities. The information is commonly
provided in the form of a Safety Data Sheet (formerly called a Material Safety Data Sheet). A Safety Data
Sheet must contain the following information about hazardous chemicals, although in the case of
confidential commercial information, the exact name of the chemical constituent or concentration may
be withheld:
o
o
o
o
o
o
o
o
o
o
o
Identification
Hazard(s) identification
Composition/information on ingredients
First-aid measures
Fire-fighting measures
Accidental release measures
Handling and storage
Exposure controls/personal protection
Physical and chemical properties
Stability and reactivity
Toxicological information
Data and Discussion
Drilling additives. Drilling fluid facilitates the drilling process by lubricating and cooling the drill bit,
transporting cuttings up the borehole to the surface and preventing them from settling when the drilling
is suspended, and exerting enough pressure to prevent the collapse of the borehole and the entry into
the borehole of liquids or gases from the surrounding rock. The drilling fluid can be water-based, oilbased, or synthetic-based. Compressed air or other gaseous substances are sometimes used. Drilling
fluids often contain chemicals that adjust viscosity, add weight, or reduce friction. An aqueous drilling
fluid would generally be composed of the following chemicals by weight: brine/water (76 percent),
barite (14 percent), clay/polymer (6 percent) and other chemical additives (4 percent). A non-aqueous
drilling fluid would generally be composed of the following chemicals by weight: non-aqueous fluid (46
percent), barite (33 percent), brine (18 percent), emulsifiers (2 percent), and gellants/other chemical
additives (1 percent) (IPIECA 2009). As drilling fluid returns to the surface, cuttings are separated using
equipment on site and the drilling fluids are reused.
Fracturing additives. Fracturing fluid is composed of water, proppant and additives. According to
FracFocus, a national hydraulic fracturing chemical registry managed by the Ground Water Protection
Council and the Interstate Oil and Gas Compact Commission, there are hundreds of chemicals that could
be used as additives, but a limited number are routinely used. “A typical fracture treatment will use
38
very low concentrations of between 3 and 12 additive chemicals, depending on the characteristics of the
water and the shale formation being fractured” (FracFocus, Chemical Use in Hydraulic Fracturing,
http://fracfocus.org/water-protection/drilling-usage).
Figure 3. Average Hydraulic Fracturing Fluid Composition
Source: ALL Consulting from FracFocus website, http://fracfocus.org/water-protection/drilling-usage
The FracFocus website displays the chart in Figure 3, which illustrates the average volumetric
percentages of additives used for hydraulic fracturing treatment in various unconventional oil and gas
plays.
The FracFocus website provides the following list of chemicals used most often in hydraulic fracturing.
Some chemicals appear more than once in the chart because they serve more than one function. The
chart is sorted by product function.
15
Chemical Name
CAS15
Chemical Purpose
Hydrochloric Acid
007647-01-0
Helps dissolve
minerals and initiate
cracks in the rock
Glutaraldehyde
000111-30-8
Eliminates bacteria in Biocide
the water that
produces corrosive
by-products
Product Function
Acid
A CAS number is a unique number assigned by the Chemical Abstract Service to each chemical entity.
39
Chemical Name
CAS15
Chemical Purpose
Product Function
Quaternary
Ammonium
Chloride
012125-02-9
Eliminates bacteria in Biocide
the water that
produces corrosive
by-products
Quaternary
Ammonium
Chloride
061789-71-1
Eliminates bacteria in Biocide
the water that
produces corrosive
by-products
Tetrakis
HydroxymethylPhosphonium
Sulfate
055566-30-8
Eliminates bacteria in Biocide
the water that
produces corrosive
by-products
Ammonium
Persulfate
007727-54-0
Allows a delayed
Breaker
break down of the gel
Sodium Chloride
007647-14-5
Product Stabilizer
Breaker
Magnesium
Peroxide
014452-57-4
Allows a delayed
break down the gel
Breaker
Magnesium Oxide
001309-48-4
Allows a delayed
break down the gel
Breaker
Calcium Chloride
010043-52-4
Product Stabilizer
Breaker
Choline Chloride
000067-48-1
Prevents clays from
swelling or shifting
Clay Stabilizer
Tetramethyl
ammonium
chloride
000075-57-0
Prevents clays from
swelling or shifting
Clay Stabilizer
Sodium Chloride
007647-14-5
Prevents clays from
swelling or shifting
Clay Stabilizer
Isopropanol
000067-63-0
Product stabilizer and Corrosion Inhibitor
/ or winterizing agent
Methanol
000067-56-1
Product stabilizer and Corrosion Inhibitor
/ or winterizing agent
Formic Acid
000064-18-6
Prevents the
corrosion of the pipe
Corrosion Inhibitor
Acetaldehyde
000075-07-0
Prevents the
corrosion of the pipe
Corrosion Inhibitor
Petroleum Distillate 064741-85-1
Carrier fluid for borate Crosslinker
or zirconate
crosslinker
40
CAS15
Chemical Name
Chemical Purpose
Product Function
Hydrotreated Light 064742-47-8
Petroleum Distillate
Carrier fluid for borate Crosslinker
or zirconate
crosslinker
Potassium
Metaborate
013709-94-9
Maintains fluid
Crosslinker
viscosity as
temperature increases
Triethanolamine
Zirconate
101033-44-7
Maintains fluid
Crosslinker
viscosity as
temperature increases
Sodium
Tetraborate
001303-96-4
Maintains fluid
Crosslinker
viscosity as
temperature increases
Boric Acid
001333-73-9
Maintains fluid
Crosslinker
viscosity as
temperature increases
Zirconium Complex 113184-20-6
Maintains fluid
Crosslinker
viscosity as
temperature increases
Borate Salts
N/A
Maintains fluid
Crosslinker
viscosity as
temperature increases
Ethylene Glycol
000107-21-1
Product stabilizer and Crosslinker
/ or winterizing
agent.
Methanol
000067-56-1
Product stabilizer and Crosslinker
/ or winterizing
agent.
Polyacrylamide
009003-05-8
“Slicks” the water to
minimize friction
Friction Reducer
Petroleum Distillate 064741-85-1
Carrier fluid for
polyacrylamide
friction reducer
Friction Reducer
Hydrotreated Light 064742-47-8
Petroleum Distillate
Carrier fluid for
polyacrylamide
friction reducer
Friction Reducer
Methanol
Product stabilizer and Friction Reducer
/ or winterizing
agent.
000067-56-1
41
Chemical Name
CAS15
Chemical Purpose
Product Function
Ethylene Glycol
000107-21-1
Product stabilizer and Friction Reducer
/ or winterizing
agent.
Guar Gum
009000-30-0
Thickens the water in
order to suspend the
sand
Gelling Agent
Petroleum Distillate 064741-85-1
Carrier fluid for guar
gum in liquid gels
Gelling Agent
Hydrotreated Light 064742-47-8
Petroleum Distillate
Carrier fluid for guar
gum in liquid gels
Gelling Agent
Methanol
000067-56-1
Product stabilizer and Gelling Agent
/ or winterizing
agent.
Polysaccharide
Blend
068130-15-4
Thickens the water in
order to suspend the
sand
Ethylene Glycol
000107-21-1
Product stabilizer and Gelling Agent
/ or winterizing
agent.
Citric Acid
000077-92-9
Prevents precipitation Iron Control
of metal oxides
Acetic Acid
000064-19-7
Prevents precipitation Iron Control
of metal oxides
Thioglycolic Acid
000068-11-1
Prevents precipitation Iron Control
of metal oxides
Sodium
Erythorbate
006381-77-7
Prevents precipitation Iron Control
of metal oxides
Lauryl Sulfate
000151-21-3
Used to prevent the
formation of
emulsions in the
fracture fluid
Isopropanol
000067-63-0
Product stabilizer and Non-Emulsifier
/ or winterizing
agent.
Ethylene Glycol
000107-21-1
Product stabilizer and Non-Emulsifier
/ or winterizing
agent.
42
Gelling Agent
Non-Emulsifier
Chemical Name
CAS15
Sodium Hydroxide
001310-73-2
Adjusts the pH of fluid pH Adjusting Agent
to maintains the
effectiveness of other
components, such as
crosslinkers
Potassium
Hydroxide
001310-58-3
Adjusts the pH of fluid pH Adjusting Agent
to maintains the
effectiveness of other
components, such as
crosslinkers
Acetic Acid
000064-19-7
Adjusts the pH of fluid pH Adjusting Agent
to maintains the
effectiveness of other
components, such as
crosslinkers
Sodium Carbonate
000497-19-8
Adjusts the pH of fluid pH Adjusting Agent
to maintains the
effectiveness of other
components, such as
crosslinkers
Potassium
Carbonate
000584-08-7
Adjusts the pH of fluid pH Adjusting Agent
to maintains the
effectiveness of other
components, such as
crosslinkers
Copolymer of
Acrylamide and
Sodium Acrylate
025987-30-8
Prevents scale
deposits in the pipe
Scale Inhibitor
Sodium
Polycarboxylate
N/A
Prevents scale
deposits in the pipe
Scale Inhibitor
Phosphonic Acid
Salt
N/A
Prevents scale
deposits in the pipe
Scale Inhibitor
Lauryl Sulfate
000151-21-3
Used to increase the
viscosity of the
fracture fluid
Surfactant
Ethanol
000064-17-5
Product stabilizer and Surfactant
/ or winterizing
agent.
Chemical Purpose
43
Product Function
Chemical Name
CAS15
Chemical Purpose
Product Function
Naphthalene
000091-20-3
Carrier fluid for the
active surfactant
ingredients
Surfactant
Methanol
000067-56-1
Product stabilizer and Surfactant
/ or winterizing
agent.
Isopropyl Alcohol
000067-63-0
Product stabilizer and Surfactant
/ or winterizing
agent.
2-Butoxyethanol
000111-76-2
Product stabilizer
Surfactant
Table 7. Chemicals commonly used in hydraulic fracturing
Source: modified from FracFocus website
Some of these chemicals are known or suspected carcinogens and can cause other adverse human
health impacts. Others commonly appear in consumer products and some have been approved as food
additives. Although fracturing fluid additives comprise a relatively small fraction of the total volume of
fracturing fluid, the volume of fracturing fluid needed for a single fracturing fluid operation is
substantial, which makes the total volume of additives needed significant (Ernstoff & Ellis, 2013; Rozell
& Reaven, 2012).
The Maryland Department of the Environment routinely requested information on drilling and fracturing
additives as part of the application for a permit to drill an oil or gas well. The applicant commonly
supplied Safety Data Sheets for the products it bought to use as additives. If the manufacturer of the
product considered the specific chemical identity or concentration to be confidential commercial
information, these would not appear on the Safety Data Sheet.
In the Interim Final Best Practices Report (MDE and DNR, 2014a), the Departments established
requirements for disclosure. These include:
o
The disclosure to MDE of all chemicals that the applicant expects to use on the site, not just
chemicals classified as “hazardous chemicals” under the OSHA Hazard Communication Standard.
o
Submission to MDE of a complete list (Complete List) of chemical names, CAS numbers, and
concentrations of every chemical constituent of every commercial chemical product brought to
the site. The information must be provided even if there is a claim of trade secrecy; in this case,
the Department will retain the list, but the list will not be considered public information.
o
If a claim is made that the composition of a product is a trade secret, the permittee must also
provide an alternative list (Alternative List), in any order, of the chemical constituents, including
CAS numbers, without linking the constituent to a specific product.
o
If no claim of trade secret is made, the Complete List will be considered public information; if a
claim is made, the Alternative List will be considered public information.
44
o
The Departments will require disclosure of chemicals used on FracFocus, so that the FracFocus
data base can be more nearly complete and useful; however, the Departments are aware that
FracFocus has a different format, and the FracFocus posting may not contain all the information
disclosed to the State.
o
The operator must provide to the local emergency response agency: a) the Complete List or
Alternative List of all chemical constituents and b) Safety Data Sheets for all products that
contain one or more OSHA hazardous chemicals, as that term is defined by the Occupational
Safety and Health Administration of the United States Department of Labor.
o
The operator must provide to the public, upon request, the same information made available to
the local emergency response agency. If the permittee provides the information to MDE in a
format MDE specifies, MDE will post the information on its website at least until the well
completion report is filed, and this will be deemed to satisfy the operator’s obligation to provide
the information to the public.
o
A person claiming a trade secret must substantiate and attest to the claim when it is submitted
to MDE, but MDE will not evaluate whether the claim is legitimate. MDE will keep the
information confidential, but may share it with other State and federal agencies that agree to
protect the confidentiality of the information. If a request is made for the trade secret
information under the Maryland Public Information Act, a process exists for challenging the
claim. MDE will require the entity claiming trade secret protection to defend against any
challenge.
o
A person claiming trade secret must provide the supplier’s or service company’s contact
information, including the name of the company, an authorized representative, and a telephone
number answered 24/7 by a person with the ability and authority to provide the trade secret
information in accordance with the regulations.
o
The regulations will require that information furnished under a claim of trade secret be provided
by the person claiming the trade secret to a health professional who states, orally or in writing, a
need for the information to diagnose or treat a patient. The health professional may share that
information with other persons as may be professionally necessary, including, but not limited to,
the patient, other health professionals involved in the treatment of the patient, the patient's
family members if the patient is unconscious, unable to make medical decisions, or is a minor,
the Centers for Disease Control, and other government public health agencies. Any recipient of
the information disclosed under this regulation shall not use the information for purposes other
than the health needs asserted in the request and shall otherwise maintain the information as
confidential. Information so disclosed to a health professional shall in no way be construed as
publicly available. The holder of the trade secret may request a confidentiality agreement from
all health professionals to whom the information is disclosed as soon as circumstances permit,
but disclosure may not be conditioned on or delayed in order to secure a confidentiality
agreement.
45
o
Upon written request and statement of need for public health purposes, the person claiming the
trade secret will disclose the chemical identity and percent composition to any health
professional, toxicologist or epidemiologist who is employed in the field of public health,
including such persons employed at academic institutions who conduct public health research.
The recipient may share the information as professionally necessary. Any recipient of the
information disclosed under this regulation shall not use the information for purposes other
than the public health needs asserted in the request and shall otherwise maintain the
information as confidential. Information so disclosed to a health professional, toxicologist or
epidemiologist shall in no way be construed as publicly available. Disclosure may be conditioned
on the signing of a confidentiality agreement before disclosure. Publication of research results
without revealing any trade secret information is not precluded. For example, provided the
publication does not disclose the trade name of the commercial product subject to trade secret
protection, or the identity of the manufacture or distributor of the product, research that
utilizes trade secret information may be published.
o
Following well completion, the operator shall provide MDE with a list of all chemicals used in
fracturing, the weight of each used, and the concentration of the chemical in the fracturing fluid.
If a claim is made that the weight of each chemical used or the concentration of each chemical
in the fracturing fluid is a trade secret, the operator may attest to that fact and provide a second
list that omits the weight and concentration to the extent necessary to protect the trade secret.
If no claim of trade secret is made, the full list shall be public information; if a claim of trade
secret is made, the list without the trade secret weight and concentration shall be public
information.
Maryland law recognizes the legitimacy of confidential commercial information and the Legislature has
adopted the Uniform Trade Secrets Act in the Commercial Law Article, Title 11, Subtitle 12. In addition,
the Public Information Act requires State agencies to deny inspection of any part of a public record that
contains a trade secret or confidential commercial information. General Provisions Article, Section 4335. In light of this State policy, the Departments considered how to address the disclosure of chemical
trade secrets while at the same time performing its obligations to protect the public and the
environment from hazards.
The public could be exposed to the commercial products themselves in the event of a release of the
product in transport or from the well pad. The emergency response agency would have sufficient
information from the Safety Data Sheets to respond to the release. If any emergency responder or
member of the public was exposed to the product itself, a physician could obtain the precise chemical
makeup of the product under the disclosure rules.
If the product had already been used in the drilling or fracturing fluid before a member of the public
were exposed, the concentration of the constituents would have changed and the constituents
themselves may have reacted to produce different chemicals. In this case, information about the
makeup of the product before it was used would be of limited use. The identity of all the chemicals in
the product would appear, however, on the Alternative List. This list would also be available to inform
any monitoring program of air or water. Lastly, all information collected by the operator at the site and
46
within the area required to be monitored must be reported to the Department. Environmental
monitoring is not protected as confidential commercial information or a trade secret, and therefore
would be available to the public, health practitioners, and public health officials.
Conclusion
The issue of chemical disclosure involves competing legitimate interests. The government must have
the information it needs to fulfill its mission. The public has an interest in knowing what chemicals are
being used in their communities. The company that developed a useful product has a right to protect its
trade secret. We have balanced all these interests by requiring that the identity of all chemicals must be
disclosed, allowing companies to protect the confidential commercial information of the exact
formulation of its products, and assuring that emergency response personnel and medical professionals
have access to the information when it is needed.
G.
Use of Fresh Water
Background
Large quantities of water are required for unconventional gas development for both the drilling and the
hydraulic fracturing phase. Maryland’s risk assessment assumes that an average of five million gallons
of water is required for each well with the majority of water used for hydraulic fracturing. It is
anticipated that water will be supplied by permitted fresh water withdrawals from surface and ground
water resources, and possibly purchases from public water systems.
If improperly managed, fresh water withdrawals could impact local and regional water supplies, degrade
aquatic ecosystems and affect water-dependent recreational uses. Withdrawals are considered
permanent because the water is generally not returned to the system and may reduce availability of
fresh water for existing and future uses, as well as downstream users. Withdrawals from streams and
rivers or from the ground water that feeds these flowing aquatic habitats could adversely affect aquatic
ecosystems by reducing flow and water levels and negatively affecting stream chemistry by increasing
temperature and reducing dissolved oxygen. In Western Maryland, there are many aquatic species,
including Brook trout, that require cool, clean and aerated streams in order to thrive and reproduce.
Recreational uses also need to be accounted for as withdrawals are planned and permitted in order that
boating, fishing, and other water dependent uses are not impacted. While any freshwater withdrawal
could have an impact, unconventional gas development is unusual in that it requires large volumes
within a compressed time frame. The rate of withdrawal that results from large quantities of water
removed over short time spans must also be considered as water appropriation permits are developed.
Data and Discussion
Maryland’s assessment of risks estimates that the total water demand for unconventional gas
development could range from a low of 75 million gallons per year to 360 million gallons per year
depending on the rate and intensity of extraction. To put this in context, during a year with average
precipitation, over 1.3 billion gallons of water falls on Garrett County, on average, each day.
47
At the level of a single well, risks from water withdrawal are expected to be low and infrequent. The
Interim Best Practices report (MDE and DNR, 2014a) states that the amount of water required for a well
exceeds the thresholds set by Maryland’s water appropriation program, and therefore a permit would
be required. Maryland is satisfied that existing criteria used to evaluate water appropriations are
generally adequate to address water withdrawals for unconventional gas development. These criteria
are designed to ensure that enough water, both in quantity and flow, remain to support existing uses
and healthy aquatic ecosystems.
The Interim Best Practices report also provides additional protection through the CGDP by requiring a
generalized water appropriation plan which will identify the proposed locations and amounts of water
withdrawals needed to support the plan. This early planning will allow MDE to flag any proposed
appropriations that may be problematic due to supply, environmental, public health or other
restrictions, allowing the CGDP-applicant time to identify alternative sources of water. Additionally, the
CGDP could lead to improved management of fresh water supplies throughout the lifetime of the plan
by a better understanding of cumulative impacts from existing and proposed appropriations. About 30
percent of the water used for hydraulic fracturing in Marcellus Shale returns as flow back, along with
some water from the Marcellus Shale formation called “produced water.” The overall water demands
will be reduced by requiring the companies to recycle 90 percent of flow back and produced water
unless the applicant can demonstrate that it is not practicable.
The risk ranking for impacts to ecological systems and aquatic species is medium (probability = medium,
consequence = moderate) because some aquatic species may be sensitive to relatively minor decreases
in water levels or flow which not otherwise cause appreciable impacts on other uses. Certain aquatic
habitats, such as the headwater areas of Use Class III (cold water) and Tier II streams are highly sensitive
to alterations in flow and stream chemistry. If withdrawals coincide with periods of droughts, adverse
impacts could occur. The coincidence of multiple stressors is unpredictable and results in the medium
risk ranking.
Conclusion
Maryland’s water appropriation program is stringent enough to generally protect all users of fresh water
resources in Western Maryland. While unconventional gas development consumes large amounts of
water, the available supplies are extensive and can easily accommodate these prospective demands.
Recycling and advances in technology that may reduce water needs for drilling and hydraulic fracturing
will further lighten the demands on available supplies. However, caution must be taken with regard to
the timing and rate of withdrawals and to specific locations that are highly sensitive; a consideration
that is addressed through the CGDP. Additional practices that could reduce risks include
1) establishment by the county or municipality of one or more semi-permanent access points at a
source with large capacity and storage options, 2) requiring applicants to perform additional modeling
for impact assessment in sensitive locations, such as Use III and Tier II waters and 3) development by
MDE and DNR of additional scientific guidance for monitoring and assessing potential ecological impacts
to sensitive streams.
48
H.
Greenhouse Gas Emissions
Background
The climate impact of natural gas is generally evaluated in two ways: the lower CO2 emissions per
kilowatt-hour of electricity generated by burning natural gas instead of coal, and the greenhouse gas
impacts of methane that enters the atmosphere by fugitive emissions and leaks. If only the emissions
related to combustion in power plants are considered, natural gas emits about half as much CO2 as coal
per kilowatt-hour generated. Methane itself, however, is a powerful greenhouse gas. It forces about 85
times the global warming of CO2 in its first 20 years and about 30 times after 100 years. 16
There have been varying estimates of the amount of methane that escapes to the atmosphere from
production, transmission, and distribution of natural gas. Estimates have been made using emission
factors, on site measurements, and atmospheric measurements. The range of estimates has been large,
and the issue cannot be considered settled.
Data and Discussion
According to Jackson et al., (2014) EPA’s estimates for methane emissions from natural gas production
operations have changed over the years, and range from between <0.2 percent and 1.5 percent. In
2013, EPA estimated a total leak rate of natural gas from production to be about 0.49 percent of total
gross production, and the total leak rate from well to end user of 1.4 percent.
A study by Allen et al. (2013) based on detailed measurements estimated production losses to be
approximately 0.42 percent of gross production, slightly less than the EPA estimate. Uncertainties in
measurements and sampling and limited sampling size contributed to a large confidence interval.
Jackson, et al. (2014) noted that this study found large differences in process-level emissions across
regions and the presence of large emitters in most regions. He also noted that atmospheric studies
found regional-scale leaking rates to be 4 percent in the oil and gas producing Denver Basin in Colorado
and 6.2 percent to 11.7 percent in the Uinta Basin in Utah.
A review of 20 years of data emissions from natural gas systems in the United States and Canada found:
(i) measurements at all scales show that official inventories consistently underestimate
actual CH4 emissions, with the NG [natural gas] and oil sectors as important
contributors; (ii) many independent experiments suggest that a small number of
“superemitters” could be responsible for a large fraction of leakage; (iii) recent regional
atmospheric studies with very high emissions rates are unlikely to be representative of
typical NG system leakage rates; and (iv) assessments using 100-year impact indicators
16
The decline from 85 to 30 is due to the rate at which methane is removed from the atmosphere. Methane has a
relatively short perturbation lifetime. The Perturbation Lifetime (PL) is a standard way of characterizing how long
molecules remain in the atmosphere. Methane is estimated to have a PL of 12.4 years, while nitrous oxide (N 2O)
has a PL of 121 years. Myhre, G., D. et al., 2013: Anthropogenic and Natural Radiative Forcing. In: Climate Change
2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change, Table 2.1 and Appendix 8A.
49
show system-wide leakage is unlikely to be large enough to negate climate benefits of
coal-to-NG substitution. (Brandt et al., 2014)
A 2012 article by Alvarez et al. examined the impact of leakage for generating electricity (well-to-burnertip) and for fueling vehicles (wells-to-wheels). With regard to electricity, the authors stated “We
estimate that natural gas produces net climate benefits relative to low-gassy coal on all time frames as
long as leakage in the natural gas system is less than 3.2 percent from well through delivery at a power
plant (i.e., excluding the local distribution system).” With regard to the use of natural gas as fuel for
vehicles, however, the authors concluded that even lower leakage rates would be needed to produce
near-term climate benefits for natural gas as a transportation fuel due to the lower carbon intensity
(relative to coal) of the fuels natural gas would replace (gasoline and diesel).
[I]f the well-to-wheels leakage was reduced to an effective leak rate of 1.6% of natural
gas produced..., CNG [compressed natural gas] cars would result in climate benefits
immediately and improve over time. For CNG to immediately reduce climate impacts
from heavy-duty vehicles, well-to-wheels leakage must be reduced below 1%.
Given that the primary niche for natural gas as a transportation fuel is heavy duty vehicles (replacing
diesel), its climate benefits as a transportation fuel appear more dubious. Also, the authors cautioned
that although the benefits increase over the long term (i.e. decades) as the large radiative forcing of
methane diminishes, the short term may be more important:
Determining whether a unit emission of CH4 is worse for the climate than a unit of CO2
depends on the time frame considered. Because accelerated rates of warming mean
ecosystems and humans have less time to adapt, increased CH4 emissions due to
substitution of natural gas for coal and oil may produce undesirable climate outcomes in
the near-term.
An analysis by Climate Central (2014) provided a tool to answer the question of the global warming
impact of switching from coal to natural gas for generation of electricity using different methane leak
rates and coal-to-gas conversion rates, projected to 2110. At a 1 percent conversion rate, gas is better
than coal for all years until the methane leak rate approaches 5 percent. Using a 2 percent leak rate and
a conversion rate of coal to gas sufficient to achieve a 25 percent reduction in coal use by 2030, the tool
predicts that by 2030 greenhouse gas emissions from the electricity sector would be about 10 percent
lower than today and, that by 2060, the reduction would reach 24 percent.
Another study (Burnham & Clark, 2012) also looked at the impacts of expanded use of natural gas in
both electricity generation and transportation. The authors identified emissions from shale gas well
completions and emissions from conventional natural gas liquid unloading as important upstream
production activities and assumed that downstream emissions for shale and conventional gas would be
similar. The analysis showed that shale gas was better than conventional gas and that both were better
than coal from a global warming potential for power plants on a 100-year timeframe. The benefit is
diminished but does not disappear for the 20-year timeframe. There was no statistical difference
between vehicles using petroleum or compressed natural gas (CNG) on the 100-year timeframe, but
50
emissions were about 25 percent higher for CNG vehicles for the 20-year timeframe. The authors noted
that there was considerable uncertainty in the data for emissions from conventional gas well liquid
unloadings and shale gas well completions and for estimated ultimate recovery. They cautioned that
the uncertainties could potentially support erroneous conclusions.
A recent article (McJeon et al., 2014) evaluated the impact up to the year 2050 of increased use of
natural gas on climate change for two scenarios: a conventional gas scenario and an abundant gas
scenario. The authors modeled the impact using five different integrated assessment models that
represent prices, demand, and supply for different fossil fuels and low-carbon energy sources. The uses
were not limited to power production. The models were run based upon climate change policies already
in effect, and did not simulate future climate policies.
The model results showed that abundant natural gas leads to greater consumption of natural gas. Coal
loses the largest market share to natural gas, but natural gas also gains market share at the expense of
nuclear and renewables. Overall, low-cost, abundant natural gas leads to increased economic activity,
reduced incentive for energy efficiency, and an overall expansion of the total energy use. The five
models predicted that the impact of abundant natural gas on CO2 emissions would range from negative
2 percent to positive 11 percent, and the impact on climate forcing would range from negative 0.3
percent to positive 7 percent.
The authors noted:
The core finding of this research is that increases in unconventional gas supply in the
energy market could substantially change the global energy system over the decades
ahead without producing commensurate changes in emissions or climate forcing. The
result stems from three effects: abundant gas substituting for all energy sources; lower
energy prices increasing the scale of the energy system; and changes in non- CO2
emissions. This result is potentially sensitive to a range of model assumptions.
Among the assumptions that could alter the result are: policies that would restrict the use of natural gas
as a substitute for low-carbon energy; technology changes that make other forms of energy more
available or less expensive; and changing rates of fugitive methane emissions. The authors also noted
that climate change is not the only implication of abundant natural gas, which can also positively affect
air and water quality17, energy security, access to modern energy, and economic growth.
17
Emissions of mercury from burning natural gas are negligible. Burning coal for energy production has been the
single largest component of anthropogenic mercury emissions in the United States, accounting for more than half
the total. Wentz, D.A., Brigham, M.E., Chasar, L.C., Lutz, M.A., and Krabbenhoft, D.P., 2014, Mercury in the Nation’s
streams—Levels, trends, and implications: U.S. Geological Survey Circular 1395, 90 p.,
http://dx.doi.org/10.3133/cir1395. The report stated “Mercury is a potent neurotoxin that accumulates in fish to
levels of concern for human health and the health of fish-eating wildlife. Mercury contamination of fish is the
primary reason for issuing fish consumption advisories, which exist in every State in the Nation. Much of the
mercury originates from combustion of coal and can travel long distances in the atmosphere before being
deposited.” The study found that methylmercury concentrations in fish exceeded levels protective of human
health in about one in four streams across the United States. The Maryland Department of the Environment has
51
Reduced emissions completion, discussed above under Air Pollution, will reduce the amount of methane
emitted during well completion. Among the other practices to reduce methane emissions that Maryland
regulations will require are a leak detection and repair program, limitations on flaring, a minimum
destruction efficiency for flares, and top-down BAT for other equipment on the well pad that can emit
methane. When evaluating top-down BAT, the applicant for the permit will be required to consider, to
the extent they apply to the applicant’s operations, EPA’s Natural Gas STAR Program’s Recommended
Technologies and Practices (www.epa.gov/gasstar/tools/recommended.html).
Even with these controls, some methane will escape. MDE will require permittees to estimate all of the
remaining methane emissions and offset them with greenhouse gas credits. The permittees will have to
estimate and report emissions to the State annually. Where practicable, estimates should be verified by
operational data from the permittee’s leak detection and repair program. When estimating emissions,
permittees must convert all methane emissions into CO2-equivalent emissions. MDE will work with
stakeholders to establish an offset program, building from ongoing efforts of the Regional Greenhouse
Gas Initiative and other greenhouse gas offset initiatives across the country. MDE may also require
permittees to offset leakage at a ratio greater than 1:1.
Conclusion
The literature supports a conclusion that minimizing fugitive emissions of methane, as will be required in
Maryland regulations, is necessary to realize any significant radiative forcing advantage over coal and oil.
Improved energy efficiency, greater reliance on sources of power other than fossil fuels, and good
climate policy will be necessary to address climate change regardless of changes in the use of natural
gas.
I.
Impacts on Habitat and Natural Resources
Background
Western Maryland has some of the state’s most important natural areas and offers diverse outdoor
recreational opportunities that rely on exceptionally high value natural resources. Shale outcroppings,
ridgelines, expansive swaths of intact forests, cave formations and clean, cold water streams provide
unique habitats for diverse and abundant aquatic and terrestrial living resources. Maryland’s GreenPrint
identifies the most ecologically important waters and lands in the State and prioritizes these areas,
referred to as “Targeted Ecological Areas”, for land conservation projects. (Maryland Greenprint,
http://greenprint.maryland.gov/.) Garrett County has the greatest amount of GreenPrint resources of
any Maryland County. Seventy-seven percent of the County has been mapped as GreenPrint and about
thirty percent is protected. Allegany County ranks fourth across the State for GreenPrint resources.
Sixty-five percent of the county’s land is within the GreenPrint and forty-two percent is protected.
Within the GreenPrint, certain habitats have been designated as “Irreplaceable Natural Areas” because
if they are lost through surface development, the habitats and species they support will not recover.
Many of Western Maryland’s rare, threatened and endangered species, such as the northern goshawk,
issued statewide advisories for gamefish and panfish in all freshwater lakes, streams, and rivers and has also
monitored mercury levels of numerous species inhabiting the Chesapeake Bay and other tidal waters.
52
green salamander, summer sedge, Indiana bat and eastern hellbenders are found within these
Irreplaceable Natural Areas. A high number of Tier II stream segments are found within this region. Tier
II streams are designated through the Clean Water Act as high quality waters and Maryland is required
to protect and maintain these streams. Many Tier II stream segments fall within the Savage River
watershed which supports the State’s most productive and interconnected stream system of Brook
trout.
Direct impacts from unconventional gas development include the conversion of lands supporting
forests, fields, and other natural resources to industrial use resulting from the well pad footprint and
associated infrastructure such as roads, pipelines and compressor stations. Maryland’s risk assessment
(MDE and DNR, 2014b) estimates that the land use footprint per well pad would be about fifteen acres,
which includes 4 acres for the well pad with the remainder needed for supporting infrastructure.
Depending on the intensity of shale gas development, the direct impact of land conversion could range
from 375 acres to 1,125 acres which would consume between 0.07 percent to 0.22 percent of the
508,200 acres of land within the Marcellus Shale exploration area. Habitats and natural resources are
also adversely affected by associated impacts resulting from habitat fragmentation, watershed
development and stream crossings. The risk assessment estimates that 1.65 miles of gathering pipelines
are needed for each new well pad. As gathering lines traverse the landscape to collect and transmit
produced gas to consumer markets, forested landscapes will be fragmented and streams will be crossed.
Forest fragmentation reduces the available deep forest interior habitats that certain species, many of
them birds, require for feeding and reproduction. Stream crossings invariably disrupt stream habitat
and can lead to increased in-stream sedimentation and bank erosion. Certain high value watersheds,
such as those containing Tier II streams, Brook trout populations or other pollution intolerant fish and
aquatic insects are very sensitive to land use changes. Eshleman and Elmore (2013) point out that
unconventional well development increases the amount of industrialized land use within a watershed
which ecologically acts like impervious surface. Increases of impervious surface at a watershed scale are
correlated with a decrease in aquatic biological diversity to due increased degradation of the physical
and chemical environments of streams. In Western Maryland, brook trout is almost entirely restricted
to watersheds with less than 4 percent impervious surfaces.
Data and Discussion
The Interim Final Best Practices report (MDE and DNR, 2014a) proposes to protect habitats and natural
resources through several measures. First, a suite of location restrictions and setbacks will prohibit well
pad and permanent surface infrastructure development within high value and sensitive natural resource
areas. For example, no well pads will be allowed within 450 feet of streams, rivers, wetlands, lakes, 100
year floodplains and other aquatic habitats. No surface development will be allowed to occur within
600 feet of special conservation areas, such as Irreplaceable Natural Areas and State designated
Wildlands. No surface development will be allowed on public lands or within 1,000 feet of sensitive cave
habitats. Development on steep slopes > 15 percent is restricted. Well pads cannot be developed within
entire watersheds that supply drinking water for the Broadford Lake, Piney Reservoir and Savage
Reservoir. These drinking water protections provide additional protection for the brook trout
populations found within the Savage River watershed. The Interim Final Best Practices report indicates
53
these restrictions would remove at least 83.2 percent (422,998 acres) of the land surface within the
Garrett and Allegany county Marcellus Shale exploration area from surface development.
Impacts to ecological systems and farmland were ranked as moderate (probability = medium,
consequence = moderate) during the site identification and preparation phase. It is inevitable that some
resource land will be converted by pad and new road development and that the environmental damage
will be localized. Most of this conversion would be of a temporary nature as site reclamation to preshale gas development conditions would be required, both during the reduction of the well pad foot
print once all wells are completed and then at the terminal phase of well abandonment and
reclamation.
Second, the CGDP provides an opportunity for landscape level planning for a company’s entire planned
operations over a five year period that gives State reviewers, the public and the applicant a means to
minimize cumulative impacts to natural resources, as well as to address community and public health
concerns comprehensively, rather than on a piece-meal basis. In addition to assuring that all location
restrictions, setbacks and other regulatory requirements are considered before permit applications are
filed, the CGDP will adhere to a set of planning principles such as preferentially locating operations on
disturbed open lands, or lands zoned for industrial activity, co-locating linear infrastructure with existing
roads, pipelines and power lines, avoiding surface development beyond 2 percent in high value
watersheds and minimizing fragmentation of interior forest habitat.
Concerns remain regarding the ecological risks associated with gathering lines which has been rated as
moderate (probability = medium, consequence = moderate) under the 25 percent extraction scenario
and high (probability = medium, consequence = serious) under the 75 percent extraction scenario.
While the CGDP will serve to reduce the specific impacts of forest fragmentation and stream crossings,
the ability to co-locate infrastructure and minimize impacts are limited because the siting of gathering
lines is not regulated and is dictated by the willingness of property owners to enter into leasing
agreements. Gathering lines are permanent alterations in that right of ways and are often maintained in
a mown condition18 throughout the life of the line which could be 20 years or more. It is because of this
permanence, uncertainty, and the clear knowledge that more well pads mean more gathering lines, that
these moderate to high risks remain.
Additional practices to protect natural resources and habitat reflect operational procedures associated
with lighting and noise management at the well pad to prevent disruption to species at sensitive
lifecycle points, such as breeding or migratory stages. Rigorous invasive species management plans will
be required to prevent accidental introduction of non-native invasive plants and animals through the
transport and use of dry materials and fluids and site reclamation activities. Concerns have been noted
in the risk assessment regarding the sensitivity of aquatic organisms to subsurface releases of flowback,
fracturing fluid and produced water. These risks to ecological systems have been ranked as moderate
(probability = low, consequence = serious). While the proposed best practices reduce the probability
that these events will occur to low, an incident could provoke a system wide response if the
18
Shrub cover is preferable to grass and should be encouraged where safety is not compromised.
54
contamination resulted in groundwater discharge to a headwater stream. Aquatic organisms are highly
sensitive to dissolved toxins through exposure to gills, egg sacs and other hydrophilic membranes, and
are less able to move away from toxic environments. Cave systems and their unique biological
communities are also particularly sensitive to groundwater toxins. The uncertainty regarding the specific
chemical composition of fluids and the specific sensitivity of the exposed organisms warrants a greater
consequence ranking.
Conclusion
The Interim Final Best Practices provide a rigorous set of protections for the abundant, diverse and
sensitive habitats and natural resources of Western Maryland. Extensive location restrictions and
setbacks, along with landscape level planning through the CGDP provides a combination of best
practices for that will achieve significant natural resource protection. Impacts from well pad
development and new roads are moderate, but temporary, and avoid the State’s most sensitive natural
resources areas. Concerns remain regarding the impacts of gathering lines that will need to be
addressed through the CGDP and through the development of siting and stream crossing guidelines
designed to minimize impacts. Contamination of groundwater is unlikely, but should it occur, rigorous
baseline and ongoing monitoring of groundwater and surface water resources should improve response
times for addressing contamination pathways and reducing the extent of impact.
J.
Impacts of Traffic
Background
Unconventional Gas Well Development using high volume hydraulic fracturing requires a substantial
amount of truck traffic. Until recently, all materials, equipment, water, proppants, petroleum products,
and chemicals have been transported to the well pad by truck, and this is still common. Because of the
heavy truck traffic, communities near well pads may experience road damage, traffic congestion, traffic
accidents, noise, and air pollution. The road network in Western Maryland is not so extensive that
alternative routes will always be available, and truck traffic for different well sites may utilize the same
roads. There can also be ecological impacts, especially from the construction of new roads.
Data and Discussion
Federal highways are constructed to withstand heavy truck traffic. State and local roads are designed for
the expected traffic, and trucks of certain sizes and weights may be prohibited. Overweight and oversize
vehicles can be addressed through State and local permits, which can include provisions on times of
travel, routes, liability, indemnity, and financial assurances. Most of the trucks associated with Marcellus
Shale gas development, however, are neither overweight nor oversize. Damage and accelerated wear
result from the sheer volume of trucks carrying legal loads on State and local roads that were not
designed to accommodate that level of use. Road damage comes in the form of cracking, rutting,
structural failure, and damage to traffic control devices and stormwater infrastructure along road sides.
Bridges can also be structurally harmed.
55
Traffic congestion is a function of the numbers of trucks, the slower speed at which trucks climb long
uphill stretches of road, and the need to stop traffic on narrow roads so trucks can pass. This can cause
significant delays for residents using the roads and could impede the movement of emergency vehicles.
The number of accidents generally rises with increased traffic, but in some areas where shale drilling has
been intense, the rate of traffic accidents or traffic deaths has gone up faster than population or vehicle
miles traveled (Muehlenbachs & Krupnick, 2014; Begos & Fahey, 2014). Oil and gas extraction workers
have a higher fatality rate than U.S. workers generally. During the 2003 to 2009 Census of Fatal
Occupational Injuries, 716 oil and gas extraction workers were killed on-the-job, resulting in an annual
fatality rate of 27.5 deaths per 100,000 workers (compared to 3.9 for all U.S. workers). Of these 716
deaths, 29 percent were highway motor vehicle crashes (CDC, 2012).
Traffic noise from trucks is closely related to the speed of the truck and how far the listener is from the
truck. A truck going 50 miles an hour may register 8 decibels higher than a truck going 25 miles per hour.
The sound level drops by 6 decibels each time the distance from the source is doubled. The sound from
a single truck passing by would exist for a short time, but multiple truck trips along the same road would
result in a higher equivalent continuous noise level (the total sound energy measured over an hour or
other time period) and higher impacts on noise receptors close to main truck travel routes. (NYSDEC,
2011).
The Noise Control Act of 1972 empowered EPA to establish noise regulations for major sources,
including transportation vehicles, and required EPA to issue noise emission standards for motor vehicles
used in interstate commerce. The law requires the Federal Motor Carrier Safety Administration
(FMCSA) to enforce the noise emission standards. In addition to standards for newly manufactured
trucks, EPA has also established for existing medium and heavy trucks used in interstate commerce with
a gross vehicle weight rating of more than 10,000 pounds. The standards are:
Speed
≤ 35 mph
> 35 mph
Stationary
Maximum Noise Level 50 feet from Centerline of Travel
83 dBA
87 dBA
85 dBA
Table 8. EPA noise levels for heavy trucks
The Maryland Department of Transportation has adopted maximum sound levels that apply to vehicles
not used in interstate commerce. The standards are adjusted depending on whether the measurements
are taken on a hard site19, or a soft site20. The standards appear in regulations at COMAR 11.14.07.08:
19
"Hard test site" means any test site having the ground surface covered with concrete, asphalt, packed dirt,
gravel, or similar reflective material for more than 1/2 the distance between the microphone target point and the
microphone location point. COMAR 11.17.07.02.
20
"Soft test site" means any test site having the ground surface covered with grass, other ground cover, or similar
absorptive material for 1/2 or more of the distance between the microphone target and the microphone location
point. Id.
56
Maximum Sound Levels Highway Operation
Type of Vehicle
Posted Speed Limit or Posted Advisory Speed
Any motor vehicle or combination
35 mph or less
Over 35mph
having a GVWR or GCWR over
Soft Site
Hard Site
Soft Site
Hard Site
10,000 pounds
86 dBA
88 dBA
90 dBA
92 dBA
Table 9. Maryland maximum sound levels for heavy trucks
Vehicles, particularly those with diesel engines, are a source of pollutants, including NOx, SO2, hazardous
air pollutants and particulate matter. The University of Maryland Institute for Applied Environmental
Health (MIAEH, 2014) noted that “evidence from traffic-related air pollution studies indicated that the
concentrations of traffic-related pollutants drop to the background level beyond 500-700m (1640-2296
feet).”
The construction of new roads for shale gas development may be limited to access roads from the
nearest public roads to the well pad. Depending on where these access roads are located, they could
fragment forests, cross streams or wetlands, or remove farmland from production. If erosion and
sediment control are not employed, stream habitat can be damaged. Trucks on these roads are likely to
stir up dust.
Among the recommendations in the Interim Final Best Practices Report that address the impact of truck
traffic on the community and the environment are the following:
Reducing the number of truck trips. By encouraging the development of multiple wells on a single well
pad, truck traffic related to pad construction, mobilization of the drill rigs, and delivery of equipment will
be lessened. Because 90 percent or more of the flowback and produced water must be recycled and
reused on site if practicable, fewer truck trips to deliver fresh water and fewer truck trips to haul away
wastewater will be needed.
Locations of pads and selection of travel routes. As part of the Comprehensive Gas Development Plan,
locations for pads, access roads, and travel routes will be evaluated for noise impacts and public health
concerns. Travel routes and times will be planned to avoid periods of heavy public use, school bus
routes when children are transported to and from school locations, and to minimize truck travel along
residential streets.
Cleaner burning fuel and engines. All on-road and non-road vehicles and equipment using diesel fuel
must use Ultra-Low Sulfur Diesel fuel (maximum sulfur content of 15 ppm). 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.
Standards for new road construction. The BMPs require that the design, construction and maintenance
of unpaved roads be at least as protective of the environment as the guidelines adopted by the
Pennsylvania Department of Conservation and Natural Resources, Bureau of Forestry, for roads in
leased State forest land (PA DCNR, 2013). This includes modifying road elevation to restore drainage,
57
sufficient compacting and top dressing, geotextiles where required, dust control, and prompt
stabilization of disturbed areas to prevent erosion, among other specifications (PA DCNR, 2011).
Road use and maintenance agreements. The travel routes will be identified during the CGDP process and
incorporated into the drilling permit for each well. As a condition of the drilling permit, an applicant shall
be required to enter into an agreement with the county and/or municipality to restore the roads which
it makes use of to the same or better condition the roadways had prior to the commencement of the
applicant’s operations, and to maintain the roadways in a good state of repair during the applicant’s
operations. The agreement may mandate that the applicant post bond.
Conclusion
The impact of increased truck traffic can be minimized but not eliminated entirely. Road damage can be
prevented if roads are improved before the heavy truck traffic begins. Local governments, through Road
Use and Maintenance Agreements, can hold companies responsible for road damage they cause. The
rate of traffic accidents does not have to increase as the volume of traffic increases, but it will rise if
drivers of passenger vehicles and heavy trucks do not obey traffic laws and pay attention. It is inevitable
that some people will experience traffic noise levels that they find objectionable and traffic delays that
they find irritating and inconvenient. These events will be episodic, but in the most extreme cases could
last for most of a year. Air pollution may be a problem for those who live very close to highly-traveled
routes. The best practices described above will reduce the likelihood of these adverse impacts.
The Departments recommend that additional measures should be taken to reduce the risk further. The
most important would be to reduce the number of truck trips. Innovations may provide the key.
In Pennsylvania, some companies are establishing centralized fresh water storage facilities from which
water can be delivered to well pads by aboveground flexible hoses, eliminating the need to truck water
directly to every well pad. The viability of this practice depends partly on the number and location of
well pads and the topography. The feasibility of such a practice should be explored in the
Comprehensive Gas Development Plan process and it should be required if it is practicable.
In Colorado, one company has established a centralized facility with all the equipment necessary for
preparing and pressurizing the fracturing fluid. The fluid can be delivered by pipes to well pads as far as
4,100 feet from the facility. This would eliminate the need to deliver water, proppant, and additives to
the well pad, and do away with the pumper trucks that otherwise are needed at the well pad.
Alternatives to using water for hydraulic fracturing should be required if they are proven to be effective
and have less impact. Substitutes such as carbon dioxide and solid rocket propellant have been
proposed.
Enforcement of vehicle laws is essential. The State Police have agreed to perform random checks of
commercial motor vehicles for compliance with weight and safety regulations if Marcellus Shale
development occurs in Maryland. The Maryland Motor Vehicle Administration has adopted sound level
limits for vehicles. Maryland Code, Transportation Article, Title 22, Subtitle 6; COMAR 11.14.07.08.
These limits are enforced by the State Police and could be checked at the same time.
58
Lastly, an outreach program to drivers of passenger vehicles and commercial vehicles should be
undertaken to educate the drivers of the challenges of sharing the roads. The American Trucking
Associations, the National Tank Truck Carriers, and the American Petroleum Institute co-chaired a
Trucking Safety Task Force that published recommendations for improving trucking safety in areas
where oil and gas development occurs (Consumer Energy Alliance). These recommendations offer a
starting point for such outreach.
K.
Community Impacts
Background
As part of the Marcellus Shale Safe Drilling Initiative led by MDE and DNR, RESI of Towson University was
tasked with examining several of the potential impact areas associated with Marcellus Shale drilling in
Western Maryland. The RESI Impact Analysis of the Marcellus Shale Safe Drilling Initiative was released
on September 22, 2014. To analyze the potential community impacts of Marcellus Shale drilling in
Maryland, RESI conducted a thorough review of relevant literature, engaged with and surveyed
stakeholders, and performed a spatial and qualitative analysis of relevant data. RESI’s discussions with
community members and local representatives revealed several major areas of concern:
o
o
o
o
o
o
o
o
Agriculture,
Education and schools,
Public health and safety,
Environmental protection,
Housing availability and values,
Infrastructure and investment,
Economic and fiscal sustainability, and
Property rights. (RESI, 2014)
Some of the topics listed above may cause impacts to the community and they are covered in detail in
other sections of this report. This section of the report will summarize RESI’s findings on potential
community impacts that are difficult to quantify, as well as, potential community impacts to agriculture,
education and schools and public health and safety.
Data and Discussion
The following subsections summarize potential community impacts that the RESI Impact Analysis of the
Marcellus Shale Safe Drilling Initiative found are of concern to stakeholders in Western Maryland but are
difficult to quantify or end up undervalued within an economic impact analysis.
Industrialization. Rapid industrialization and the jobs that come with it can lead to rapid population
growth that strains public services and disconnects long‐term residents from their communities. During
a boom cycle, local investment leads to high annual economic growth rates in once sparsely populated
rural towns. The capacity for small, rural communities to handle rapid industrialization is limited, and
problems arise as communities strain already limited resources in response to increased demand on
local infrastructure and services. The potential benefits of rapid industrialization may be great, but
59
communities with little knowledge of or ability to prepare for rapid industrialization may not fully
capture these benefits.
Following rapid industrialization, any benefits successfully captured within the community may not be
distributed evenly among the residents. Some people will profit from jobs, royalty payments or indirect
positive economic effects, while others will experience only the inconvenience and disruption, and
possibly adverse impacts on their quality of life and the environment. If Marcellus Shale gas
development moves forward, an imbalanced distribution of benefits amongst residents can corrode the
community, or divide the community by perceived winners and losers. (RESI, 2014, p. 101).
Disruption. The Boomtown Impact Model associates rapid population growth and rapid energy
development with increases in stress, changes in individuals’ interactions within the community,
decreased community cohesion, and poor community character; all of these changes are a disruption to
the community. When a resident can quickly identify the type of place in which he or she lives (a farm
town, a resort town, etc.), what his or her role in that place is (a farmer, business owner, or community
leader), and what his or her relationship is to others (a friend, partner, or employer), then that resident
is strongly tied to his or her community. Formerly strong ties to the community are hard to repair when
those roles and relationships are disrupted by an imbalance of benefits and costs throughout the
community.
RESI’s engagement with local stakeholders and residents indicate strong ties to agriculture, tourism,
construction, and existing energy activities. Based on feedback during the stakeholder engagement
process, Western Maryland residents appear very clear on their roles in the community. However, the
stress of potential changes to the community could impact relationships and trust in political leadership.
Stress can lead to increases in social problems (crime, substance abuse, etc.), a lowered standard of
living, strained local services, and general disorganization. This tendency is especially true for rural
communities. Conversely, urban communities are more able to absorb rapid population growth and
industrial development. (RESI, 2014, pp. 102 – 103).
Agriculture. Stakeholders in Western Maryland indicated support from the farming community for
responsible natural gas development. Agribusiness and natural gas development currently coexist in
Accident, Maryland (in Garrett County), where gas pipelines, storage wells, and a large compressor
station are located. Farmers’ positive perceptions of drilling in Western Maryland are credited to
farmers currently farming around storage wells without significant health or environmental impacts.
Stakeholders identified the largest perceived impact to be the stigma of the industry and occasional
small leaks. Stigma and negative perceptions, in comparison to environmental and economic impacts of
an area, can be difficult to eliminate through policy changes, and interviewees acknowledged that larger
wells with greater impacts are anticipated should horizontal drilling occur.
Farmland is often protected from extractive industries, especially surface mining, by conservation
easements which serve the purpose of protecting natural ecosystems, recreational areas, and other
important open spaces. Different laws regarding conservation easements and split estates complicate
60
farmers’ rights to lease property for natural gas drilling. There are conservation groups in support of
drilling and conservation groups against drilling on eased land.
Migration of labor from farms to out‐of‐state well pads can reduce the time local farmers can devote to
maintaining their agribusinesses. Allowing Marcellus Shale drilling in Maryland could allow these
farmers to spend more time on the farm and with their families, while also earning supplemental
income working in the natural gas industry or through leasing of mineral rights. Furthermore,
stakeholders expressed the opinion that different scenarios could play out if drilling is permitted on
agricultural land:
1. Lease and royalty payments from shale development would sustain farmers who are otherwise losing
money, allowing farmers to sustain their farms after the inevitable “bust” phase of drilling, or
2. Farmers will use the lease and royalty payments to retire from farming, creating a near extinction of
agribusiness in Western Maryland, and therefore less economic diversity. (RESI, 2014, pp. 104 – 106).
Schools. Allegany County Public Schools comprised 22 schools, 14 public elementary schools, four public
middle schools, one technical school and one alternative school. Garrett County Public Schools
comprised eight elementary schools, two middle schools and two high schools.
Drilling is expected to bring a significant number of jobs into Maryland. As a result, there is the potential
for overcrowding of schools if new workers bring young families with them. This possibility is of
particular concern for Garrett County, where an education funding deficit in the millions and a decline in
the population of school‐aged children have led to school closures.
If the population of young families suddenly increases, the remaining facilities may not have the capacity
for more students. Stress on teachers and administrators could present both health risks and a potential
decline in the quality of education in the area. In addition, increased truck traffic is expected, and raises
concerns regarding increases in traffic along school bus routes.
Both counties may need to consider either regulating traffic so that trucks and school buses are on the
road during separate hours or assuring that trucks and buses use separate routes. Stakeholders stressed
that, in existing conditions, Garrett County graduates a number of bright students from high schools and
nearby colleges but does not currently provide the requisite balance of job opportunities for its
graduates. Graduates either struggle to find gainful employment within Western Maryland or leave the
region. A potential positive impact of allowing drilling in Western Maryland would be an increase in job
opportunities for residents. (RESI, 2014, pp. 106 – 108)
Conclusion
The numerous concerns regarding natural gas drilling’s impact on Western Maryland’s communities can
be difficult to quantify. Western Maryland’s legal, natural, and political environments are different from
those in West Virginia and Pennsylvania and the impact on communities may be different. There are
steps that local jurisdictions can take to avoid the possible negative impacts.
61
L.
Industrialization of Landscape21
Background
The prevailing landscapes of Garrett and Allegany Counties are dominated by forest cover interspersed
with areas of residential, commercial and industrial development concentrated primarily within
municipalities (Error! Reference source not found., Error! Reference source not found.). The Maryland
partment of Planning classifies the land area of Maryland into 13 distinct types of land use (i.e. low to
high density residential, commercial, industrial) or land cover (i.e. agriculture, forest) and has mapped
changes in land use/land cover since 1973. (Maryland Department of Planning, Land Use/Land Cover,
http://planning.maryland.gov/OurWork/landuse.shtml.) The most current assessment of land use
reflects 2010 conditions.
Figure 4. Garrett County 2010 Land Use / Land Cover
In Garrett County, about 20 percent of the land is publicly owned, primarily as state forests and state
parks. About 90 percent (377,496 acres) of the land area supports rural resources which are defined as
21
The Maryland Department of Planning contributed to this section and reviewed it for accurracy and
completeness.
62
agriculture, forest, extractive/barren/bare and wetlands. Of that area, 75 percent consists of forest land.
In Allegany County, 87 percent (230,930 acres) of the land area supports rural resources and, of that, 87
percent exists as forest land.
Recent land use changes in Garrett County since 2002 show an increase in developed land by 4,107
acres with a similar decrease in resource lands; about 78 percent of that as forest and the remainder
primarily agricultural land. In Allegany County, developed land increased by 3,386 acres from the loss of
resource lands; about 65 percent of that as forest and the remainder primarily agricultural land.
In Garrett County, most new development is occurring adjacent to existing development, although there
are some instances where new development occurs as pockets within rural resource lands. In Garrett
County, most of the new growth is very low and low density residential development while in Allegany
County, new growth is primarily classified as low density residential and other developed
lands/institutional/transportation.
As noted in the Garrett County 2008 Master Plan, Garrett County contains the incorporated towns of
Accident, Deer Park, Friendsville, Grantsville, Kitzmiller, Loch Lynn Heights, Mountain Lake Park and
Oakland, which is the county seat (Garrett County, 2008). Just over 20 percent of the County’s total
population lives within these towns. The towns have their own planning authority and adopt their own
comprehensive plans and land use regulations. The Comprehensive Plan also recognizes 11 Rural
Villages. Formal land use planning in Garrett County began in the 1970s, starting with the Deep Creek
Lake area which included regulation of land use within the Deep Creek watershed. Apart from the
towns, this is the only part of the county that is subject to land use regulations. The remainder of the
county is subject to a subdivision ordinance that controls the subdivision and development of land, but
not the use of land. Garrett County does not have county-wide zoning. The majority, if not all, of the
Marcellus Shale drilling will occur on properties that are not regulated by a zoning designation.
In Garrett County, zoning controls prohibit the development of oil or gas wells within the 2,000 foot
buffer surrounding Deep Creek Lake. The town of Mountain Lake Park approved an ordinance in 2011
that bans the creation of new gas wells. The Comprehensive Plan recommends working with the
Maryland Department of the Environment, State Highway Administration, other state agencies and
energy companies to monitor natural gas development activities to ensure the safety of the ground and
surface water supplies, to protect sensitive environmental areas, to address the socioeconomic impacts
of natural gas drilling, and to ensure the safety and adequacy of roads to accommodate natural gas
drilling activities. The Garrett County Subdivision Ordinance defines Scenic Views or a Viewshed in
Article 2 § 159.016, A.(46) Definitions. Scenic Views are mentioned in several sections of the ordinance
with emphasis on preserving the scenic views and the rural character of a development.
The current Allegany County Comprehensive Plan of 2014 provides for land use planning and zoning for
the entire county and is addressed by planning region. Population between 1990 and 2010 has
increased in the Greater Cumberland, Greater Frostburg and Middle Potomac planning regions. There
are seven incorporated municipalities. Cumberland, Frostburg, Lonaconing and Westernport exercise
their planning and zoning authority through comprehensive planning while Barton, Luke and Midland do
63
not. Allegany County’s Mineral Resources Element of the Comprehensive Plan promotes exploration of
natural gas in the Marcellus shale formation by encouraging policymakers and regulators to engage in
the Marcellus Shale Safe Drilling Initiative Advisory Commission (Allegany County, 2014). Allegany
County’s Land Development Ordinance, §360-59 defines 1) Subsurface Mineral Extraction as deep
mining for coal and other minerals, drilling for oil and gas and other minerals and includes surface
structures related to the mining use and 2) Extractive Industry Surface or subsurface mines for coal, clay,
stone or other minerals; quarries; oil or gas drilling; sand and gravel pits; and borrow pits. Exploration
for the above is permitted in all districts except the R or G-1 Districts with Board of Appeals approval.
Figure 5. Allegany County 2010 Land Use / Land Cover
Data and Discussion
Category
1973
Total developed lands (Allegany)
2002
2010
21059
32468
35853
Total resource land (Allegany)
245630
234316
230930
Total land (Allegany)
266689
266784
266783
64
Category
1973
Total water (Allegany)
2002
2010
2820
2725
2725
13368
37689
41797
Total resource land (Garrett)
406425
381603
377496
Total land (Garrett)
419293
419293
419293
5635
5767
5767
Total developed lands (Garrett)
Total water (Garrett)
Table 10. Land Use in Allegany and Garrett Counties
These data indicate that the percentage of total land developed in Allegany County increased from 1973
to 2010 from 7.9 percent to 13.4 percent and approximately 14,794 acres were developed during that
time. The percentage of total land developed in Garrett County increased from 1973 to 2010 from 3.2
percent to 10 percent and approximately 28,429 acres were developed during that time.
Towson University’s Regional Economic Studies Institute (RESI), in consultation with the Departments,
developed two scenarios of the effects of shale gas development on rural resources. Scenarios 1 and 2
assume 25 percent and 75 percent extraction levels, respectively, of the available Marcellus natural gas
resource in Maryland (Table 10. Land Use in Allegany and Garrett Counties). Activity scope and duration
associated with each different scenario were evaluated during each shale gas development phase. It is
important to note that these scenarios, while plausible, were constructed specifically to mimic the
“boom and bust” cycle that is associated with most mineral extraction operations. The actual pace and
intensity of development could differ from the scenarios.
Item
Scenario 1 Scenario 2
Extraction Level
25%
75%
Wells per pad
6
6
Average Wells Drilled/Year 15
45
Total Wells Drilled
450
150
Total Number of Well Pads 25
75
Table 11. Well and Well Pad Development Activity for Scenarios 1 and 2
Based upon information from New York (NY DEC, 2011) and information gathered from UGWD
applications submitted to the Departments, the land use footprint is assumed to be 15-acres of total site
disturbance/land clearing per well pad developed. This estimate includes about 4 acres for the well pad
with the remainder needed for roads, pipelines and other supporting infrastructure.
65
Under scenario 2, the build out predicted for Allegany County is 10 well pads; if each well develops 15
acres, 150 acres would be developed, or 0.06 percent of all the land in the County. Garrett County is
larger and less developed than Allegany County. Garrett County is predicted to support 65 well pads
under scenario 2. If 65 well pads are constructed, 975 acres would be developed, representing 0.23
percent of land in the County. Therefore, depending on the intensity of shale gas development, a
conversion of land to industrial use could range from 375 acres to 1,125 acres. Most of this conversion
would be of a temporary nature as site reclamation to pre-shale gas development conditions would be
required.
The proposed Comprehensive Gas Development Plan (CGDP) and the recommended location
restrictions and setbacks are highly effective for stabilizing significant land use change. The CGDP is an
opportunity to apply a broad-scale proactive planning perspective by considering the entire project
scope of a company, rather than responding shale gas development on a permit by permit basis. The
CGDP requires adherence to the suite of location restrictions and setbacks. According to the Part II:
Interim Final Best Practices Report, published in July 2014, these restrictions would remove 83.2 percent
(422,998 acres) of the land surface within the Garrett and Allegany County Marcellus Shale exploration
area from surface development. These restrictions would leave 85,172 acres available for surface
operations. If surface area above the Accident Gas Storage Field were also excluded from well pad
development due to incompatible uses, the surface constraints increase to 84.7 percent (430,559 acres),
leaving 77,510 acres of the exploration available for surface development. These figures do not account
for setbacks from private drinking water wells.
The nature of the restrictions are to focus shale gas development in areas that are primarily composed
of farm and forest land and are far removed from population centers and occupied structures. If the
most intensive extraction level occurred, resulting in the development of 75 well pads and associated
supporting infrastructure, the temporary conversion of largely rural resource land would amount to 0.22
percent over the entire exploration area (508,169 acres) in Garrett and Allegany counties.
Conclusion
The CGDP can further minimize impacts to land use patterns and the rural character of Western
Maryland by modifying where the land use impacts and how those locations interact with the rural
landscape values that epitomizes this area. CGDP planning principles will address viewshed impacts, colocating linear infrastructure to reduce fragmentation of forested landscapes, and closely evaluating the
timing and pattern of transportation needs and road traffic to address concerns faced by rural villages
and towns. Additional planning maps that will be included in the Shale Gas Development Toolbox will
provide information related to identifying tourism and recreational sites to help avoid visual impacts of
drilling from both the drill pad and activity on access roads on these tourism amenities.
In Maryland, county and municipal jurisdictions have local land use authority that can be leveraged to
refine where shale gas development occurs. Although most of the actual drilling will occur in the rural
areas of each county, municipalities will be impacted. Local governments are advised to consider
impacts to tourism, recreation and Heritage Areas and should review practices and case studies from
adjacent areas, such as Greene County, Pennsylvania, that have experienced drilling activity.
66
M. Influx of Workers
Background
The natural gas industry, like most extraction industries, experiences a “boom and bust” cycle. The
demand for labor is highest during the active development phase, when wells are being drilled and
pipelines are being laid. Some of this labor will likely be met by the existing residential labor force.
There will also be an influx of out of state workers to fill the demand during the active development
phase.
Data and Discussion
RESI (2014) assessed employment based on no drilling and the 25 percent and 75 percent extraction
drilling scenarios over the first 10 years of drilling, assumed to be the “boom” period (2017-2026). RESI
expects that, during the “boom” years, the greatest change from the baseline employment will occur in
2021, adding between 1,240 jobs in Scenario 1 and 2,425 jobs in Scenario 2, $148.4 million in economic
output in Scenario 1 and $348.6 million in economic output in Scenario 2, and $35.4 million in wages in
Scenario 1 to $76.7 million in wages in Scenario 2.
This increased economic activity in the region may incentivize some individuals previously commuting to
relocate to the region. RESI found that more than 60 percent of the current workforce used in
Pennsylvania or West Virginia drilling operations were from Maryland. Using this assumption, this could
indicate that of the new jobs in the region, more than 30 percent will be taken by commuters into the
area.
RESI used projected inmigration directly related to growth in employment in the natural gas industry to
form a conservative estimate of the resident share of new direct jobs. Based on current commuting
patterns in Western Maryland, RESI assumed an estimated 58.9 percent and 61.4 percent of spinoff jobs
in Allegany and Garrett Counties, respectively, would be acquired by new residents living and working in
each county.
Following peak years of drilling, the influx of new residents peaks in 2021 with 744 new residents in
Scenario 1 and 1231 new residents in Scenario 2. Though the total number of households continues to
increase over the ten‐year period, the presence of drilling in Scenarios 1 and 2 will create a large,
transient influx of residents at the early stages of drilling followed by slower year‐over‐year growth in
household population compared to the baseline scenario.
Conclusion
The influx of workers to Garrett and Allegany Counties will be highest during the active development
phase. Some of these jobs will be filled by the existing residential labor force of both Counties. Some
jobs will be filled by new residents that permanently relocate to the area, while others will be filled by
transient out of state workers who do not intend to permanently relocate to the area. The new workers
that permanently or temporarily relocate to the area could put pressure on the housing market, local
schools, roads and transportation, broader community services and infrastructure, and social services.
The Counties are well-positioned to accommodate the additional workers if advance planning occurs.
67
N.
Availability of Housing
Background
The demand for labor and, consequently, housing is highest during the active development phase, when
wells are being drilled and pipelines are being laid. While some of this labor may be met by an existing
residential labor force, there will be an increase in new workers that will be seeking housing close to
their work. Many of these workers will only need temporary housing as they move from job to job. In
rural areas, the available housing supply may not be adequate to meet these demands. As a result,
highly paid gas industry workers, who can pay higher rents, may use available housing, such as rental
units or hotels and displace low income residents or tourists. Both of these effects adversely affect the
Western Maryland economy and could lead to increase in homelessness for displaced residents.
Data and Discussion
RESI (2014) assessed existing housing, projected populations changes and housing demands based on no
drilling and the 25 percent and 75 percent extraction drilling scenarios over the first 10 years of drilling,
assumed to be the “boom” period (2017-2026). In the absence of drilling, Allegany County has a small
surplus of available (for sale or rent) housing units. Under both extraction scenarios, the county will
experience a shortage in available housing by 2019. If unavailable housing is included, which is vacant
housing currently not for sale or rent, there will be no shortage under either scenario. In Garrett
County, RESI determined that there would be no housing shortages, in either available or unavailable
housing, whether drilling occurred or not. However, this assessment did not account for the Deep Creek
Lake second-home and vacation rental market. When housing units in the Deep Creek Lake area were
excluded from the analysis, housing shortages were apparent. With or without drilling activity, Garrett
County will have a total housing shortage, which includes both available and unavailable housing.
Shortages of available housing are immediate and exist for all ten years. Under no drilling, total housing
shortages would occur in 2022. Under both extraction scenarios, total housing shortages are probable
in 2020.
A typical natural gas industry employee earns roughly $40,000 more in household wages than about half
of Western Maryland residents. This raises concerns that potential increases in rental rate will displace
local residents with lower income. Residents with short-term leases and lower income are the most at
risk. In areas of intense drilling, higher rental rates and displacement of residents can lead to increases
in homelessness leading to higher demand for foster care services, increases in school dropout rates,
and eventually higher demand for public assistance. RESI suggests that if the influx of workers is
relatively short-term, renters may not be impacted if long-term leases are held, month-to-month leases
or daily rates for temporary housing, such as hotel rooms, would be more vulnerable to rising rates. A
review of the effects of Marcellus Shale gas extraction on housing in Pennsylvania notes that landlords
in small communities with supplies of housing similar to Allegany and Garrett Counties preferred renting
to long-term residents and rental rates rather than dealing with the cost and effort of finding new
tenants among a transient, high-turnover workforce. If rents were increased at all, they were only
raised by 5 to 10 percent. (Williamson & Kolb, 2011).
68
RESI (2014) suggests that rental ordinances and exclusionary zoning ordinance could assist in the
management of severe changes in housing needs. New construction is a short-sighted solution which
could result in long-term blight through an excess of vacant and poorly maintained housing stock once
the gas industry workforce leaves the area. Housing needs can be addressed by repurposing existing
structures. For example, a closed school could be converted to housing.
Conclusion
Allegany County has adequate housing supplies to meet increased demands from unconventional gas
well development. Garrett County may face housing shortages under the assumption that housing units
in the Deep Creek Lake will not be available for an influx of gas industry workers. This shortage is
anticipated even if drilling does not occur. While Garrett County may elect to build new housing, they
are cautioned to not over extend county resources and plan for accommodating a temporary workforce
while protecting housing supply for existing residents and the tourism industry.
O.
Economic Impact: Gas Production
Background
Gas development and production will bring economic benefits to the region in terms of jobs, wages and
tax income. As noted in the MIAEH (2014) health report, an improved economy and jobs for local
residents can provide benefits for the community and for health care. “Revenue flows from the
extraction of natural resources, when distributed in an effective and equitable manner, can fund public
services such as healthcare infrastructure; the potential increase in workers with health insurance can
also have a positive impact on local health care industry.” (Citation omitted)
Data and Discussion
In the economic study, RESI (2014) used a dynamic input/output model, a willingness to pay model, and
a hedonic pricing model to estimate the impacts. RESI modeled baseline (no drilling), extraction of 25
percent of the available gas, and extraction of 75 percent of the gas over a 20 year period. In each case,
all the wells were drilled in the first ten years to mimic the cyclical nature of most extractive industries.
Royalty payments go to the owner/lessor of the mineral rights. Because mineral rights are often
separated from the surface rights, and there was no way to determine if royalty payments would add to
the household income of residents, in its model, RESI included royalty payments as an increased
production cost, but not as increased disposable income to households. The total royalty payments
were calculated, however.
Reproduced here are the summary charts from the RESI report:
Impact
Employment
Wages
Output
Tax revenues
Severance tax revenues
Total at Peak
Annually, 2017-2026 Annually, 2027-2036
492
224
9
$12.6 million
$5.9 million
-$0.6 million
$49.7 million
$25.5 million
$1.8 million
$0.9 million
$0.4 million
$0.1 million
$1.0 million
$0.6 million
$6,624
Table 12. Economic and Fiscal Impacts for Allegany County – Scenario 1, 25% extraction
69
Source, RESI, 2014 Figure 1
Impact
Employment
Wages
Output
Tax revenues
Severance tax revenues
Total at Peak
Annually, 2017-2026 Annually, 2027-2036
908
682
67
$26.4 million
$18.7 million
-$0.9 million
$101.8 million
$76.3 million
$9.2 million
$1.8 million
$1.3 million
$0.4 million
$2.3 million
$2.0 million
$68,645
Table 13. Economic and Fiscal Impacts for Allegany County – Scenario 2, 75% Extraction
Source, RESI, 2014 Figure 2
Impact
Employment
Wages
Output
Tax revenues
Severance tax revenues
Total at Peak
Annually, 2017-2026 Annually, 2027-2036
1,240
1,018
136
$35.4 million
$29.7 million
$0.5 million
$148.4 million
$122.4 million
$16.2 million
$2.5 million
$1.9 million
$0.6 million
$4.2 million
$3.5 million
$0.3 million
Table 14. Economic and Fiscal Impacts for Garrett County – Scenario 1, 25% Extraction
Source, RESI, 2014Figure 3
Impact
Employment
Wages
Output
Tax revenues
Severance tax revenues
Total at Peak
Annually, 2017-2026 Annually, 2027-2036
2,425
1,848
-44
$76.7 million
$60.6 million
-$3.5 million
$348.6 million
$264.0 million
$12.5 million
$3.6 million
$2.9 million
$0.3 million
$13.5 million
$9.9 million
$0.6 million
Table 15. Economic and Fiscal Impacts for Garrett County – Scenario 2, 75% Extraction
Source, RESI, 2014 Figure 4
Royalty payments will benefit the owners and lessors of the mineral rights, who may or may not reside
in Maryland. The royalties paid out are shown in Table 16. Estimated Royalty Payments Made by Firms
Extracting Gas in Allegany County Table 16 (Allegany County) and Table 17 (Garrett County).
Year
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Scenario 1
$573,500
$1,161,024
$1,433,345
$1,710,135
$1,710,135
$1,838,985
$1,216,533
$599,171
$320,939
$179,353
70
Scenario 2
$1,720,501
$4,403,774
$4,668,713
$4,183,495
$4,183,495
$4,057,007
$4,090,765
$4,124,016
$2,644,684
$1,317,217
Year
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
Scenario 1
$98,997
$54,296
$28,565
$14,113
$5,948
$1,260
$0
$0
$0
$0
Scenario 2
$701,536
$382,648
$208,304
$113,545
$59,610
$29,428
$12,413
$2,704
$0
$0
Table 16. Estimated Royalty Payments Made by Firms Extracting Gas in Allegany County
Year
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
Scenario 1
$1,720,501
$4,710,674
$10,127,485
$10,351,518
$9,638,948
$8,734,644
$8,150,687
$8,285,283
$8,337,173
$6,206,058
$2,963,094
$1,587,204
$853,849
$466,148
$254,143
$134,945
$68,738
$30,870
$8,488
$0
Scenario 2
$8,602,507
$22,018,869
$26,168,444
$26,876,035
$30,759,793
$26,767,166
$23,639,728
$22,325,666
$23,218,113
$15,442,431
$7,515,478
$4,026,382
$2,180,602
$1,192,496
$638,059
$334,699
$168,545
$75,261
$16,977
$0
Table 17. Estimated Royalty Payments Made by Firms Extracting Gas in Garrett County
Sources: EIA; RESI, 2014
If the recipients of royalty payments reside in Allegany or Garrett Counties, the impact on individual
households could be substantial. RESI postulates two extreme outcomes for farmers: lease and royalty
payments from shale development would sustain farmers who are otherwise losing money, allowing
farmers to sustain their farms after the inevitable “bust” phase of drilling; or farmers will use the lease
and royalty payments to retire from farming, creating less agribusiness in Western Maryland, and
therefore less economic diversity.
Allegany County, having a larger number of jobs and a fewer number of potential sites for gas wells,
experiences modest job growth during the boom years and declines to near baseline (although still
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above baseline) at the end of the 20 year period. Figure 6. Garrett County, on the other hand,
experiences a more dramatic increase in employment during the boom years, but under Scenario 2
actually has lower employment during the bust cycle. Figure 7. The boom and bust cycle shown here is a
product of the scenarios, but it is not atypical of resource based industries. If the pace of development
were slower, the changes would be more gradual, but the tax revenue to the Counties does not last.
Reliance on these revenues could leave the Counties in a difficult budgetary position when gas
production is over.
Conclusion
Gas development could bring significant income and economic growth to Western Maryland until the
gas is fully extracted. Local governments should be mindful of the danger of relying on resource
extraction instead of diversifying their economies.
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Figure 6. Employment Impacts in Allegany County
Figure 7. Employment Impacts in Garrett County
73
P.
Economic Impact: Property Values
Background
Data show that property values are impacted by drilling activity, particularly as one gets closer to the
drilling activity. There can be an increase in property values for properties not in very close proximity to
a well but in the general vicinity of a well. However, there can be a significant drop in property values
near active well sites, and it can persist for decades.
Data and Discussion
RESI (2014) analyzed proximity to operational wells and determined that the closer the wells are to
residential areas, the lower those residential property values will be. The decline in home values may
impact resale values for homeowners as well as their tax payments over time.
A 2012 study by Muehlenbachs, Spiller, and Timmins found home values for homes located in
Washington County, Pennsylvania near well sites and reliant on well water declined by 26.6 percent. In
a 2013 study, the same authors analyzed property transactions from 36 counties in Pennsylvania and 7
counties in New York. (Muehlenbachs, Spiller, & Timmins, 2013). Similar to the findings from their study
of Washington County, their findings indicated that properties relying on private drinking water wells
were negatively affected by nearby shale gas wells whereas those properties that had access to public
water were positively affected. However, the negative effect for groundwater dependent homes
became greater the closer the well, and the positive effect for public water homes became smaller. For
properties not in very close proximity to a well but in the general vicinity of a well (i.e., within 12 miles),
property values are seen to increase.
Additionally, according to RESI’s model for housing in the region, the existing vertical gas wells in the
Garrett and Allegany County area have depressed the value of properties within a half‐mile of a well by
7 to 9 percent relative to a comparable home more than two miles away. This analysis was done over
time, indicating that wells within the region have some underlying impact on people’s perception of a
home. Despite the wells being drilled in some cases more than 50 years ago, the environmental and
health concerns may still affect an individuals’ decision when purchasing a home.
Drilling for, producing and storing gas are permitted by right in all zoning districts governed by the Deep
Creek Watershed Zoning Ordinance, subject to State and federal regulations and the following setbacks:
2,000 feet from the high water elevation of Deep Creek Lake; and 1,000 feet from the property line of
any lot not owned or leased to the entity responsible for the gas drilling, producing or storage operation.
Unless the zoning ordinance is amended, there is a risk of significant loss in tax revenue to the County.
The lack of zoning in areas outside of the Deep Creek Lake area is suspected to have impacted property
values in Garrett County, and a lack of regulation on land use could be increasingly detrimental with the
presence of increased industrial activity.
A decline in property valuation has a significant impact on resale value as well as fiscal revenues. The
local share of property taxes begins to demonstrate the impact of the property value decline by 2032.
Revenues by 2032 in Garrett County begin to fall below baseline projections. The fall in property tax
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revenues is a direct result of the decline in the property values associated with those homes within a
half-to one-mile of natural gas wells.
Conclusion
Drilling activity clearly has an impact on property values. This impact generally is negative, and results in
a drop in property values. This impact is felt the most strongly for properties nearest active well sites.
This can negatively affect resale values and property taxes, and can persist for many decades after
drilling stops.
Q.
Economic impact: Tourism
Background
The foundation of Western Maryland’s tourism economy is its rural character and natural beauty that
attracts visitors to this region for outdoor recreational pursuits and its second-home market, particularly
in the Deep Creek Lake area. In Garrett County, a majority of sales tax revenue is generated by tourism
and is heavily influenced by resort, recreation, amusement and outdoor sports attractions. There is
great concern that impacts from poorly managed unconventional gas well development could adversely
affect scenic viewsheds, wildlife, water quality, open space and the other natural resource amenities
that bring visitors to this region to hike, fish, hunt, boat and vacation. Bad press from accidents or leaks
could dampen tourism. Potential visitors may choose to go elsewhere if they perceive their experience
may be impacted by environmental degradation. The natural gas industry could limit access to tourism
destinations through increased traffic or road damage and reduced lodging capacity. In addition to these
losses in revenue, tourism and recreation business owners could also be affected by a reduction in
available labor or reduced access to land and water destinations.
Data and Discussion
The economies of Allegany and Garrett Counties have unique attributes in that each has a few set of
industries that employ the majority of area residents. In Allegany County, the top five industries are
Health Care and Social Assistance, Retail Trade, Accommodation and Food Services, Manufacturing, and
Administrative and Waste Services. Garrett County’s top five industries are more reliant on tourism and
include Retail Trade, Accommodation and Food Services, Manufacturing, Construction, and Arts and
Entertainment.
RESI evaluated existing studies and data from regions undergoing active shale gas extraction and found
that tourism-related impacts are less well documented than other economic and community impacts. In
part, this was due to a lack of available, uniform data on hotel tax revenues, industry-level employment
and other key indicators needed to evaluate effects of the gas industry on tourism. For example,
occupancy rates did not differentiate between “visitors” who were tourists and “visitors” who were
employed at drill sites. In addition, RESI noted that other economic factors, such as the housing
recession and presence of other extractive industries that might also impact tourism, were difficult to
separate out from those associated with the shale gas extraction industry.
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RESI’s research identified some qualitative impacts associated with unconventional gas well
development. Businesses affected by tourism, either directly or indirectly, will be drawing from the
same resources; labor, water and land, that the gas industry relies on. Businesses may be faced with
needing to increase wages in order to compete with the higher salaries offered by the gas industry.
Hotel and other lodging capacity may be reduced for tourism if alternative housing cannot be identified
for the transient gas industry workforce. Traffic and road damage may reduce visitors’ access or interest
in traveling to Western Maryland. Because nonresidents and second-home owners have more flexibility
in where they choose to vacation, the perceptions of adverse impacts to environmental quality and
tourism based services are highly influential. While there may be an economic downturn in the tourism
industry, this could be offset by an upswing of increased hotel taxes. Local governments should
evaluate existing hotel and amusement tax policies to fully capture the expenditures of a transient
workforce and to sustain the entire tourism industry in the long term. RESI also suggested implementing
a conservation fund to mitigate impacts and maintain aesthetic qualities. Residents demonstrated a
willingness to pay $16/year to support this goal.
The Interim Final Best Practices report (MDE and DNR, 2014a) provides the careful planning and
regulatory framework needed to minimize the impacts of unconventional gas well development that
could adversely affect the tourism economy. Maintaining the rural character of Western Maryland’s
landscape, particularly as visitors enjoy scenic vistas as they travel to and around the region is critical.
The greatest visual impacts are temporary, spanning the period of construction of the pad and road to
production phase. Lights and flares will be visible at night. Once the well is in production, the visual
impact is less, although there may be pipeline rights of way that could bisect forested landscapes. While
mainly temporary, these impacts are addressed through a range of visual mitigation measures that
include viewshed analysis for siting decisions, visual barrier and camouflage techniques, management of
night lighting and controls on flaring. The CGDP requires transportation planning to avoid heavy truck
traffic during times of high tourism activity. The CGDP, location restrictions and setback, engineering
design standards and controls, water and waste management requirements, site reclamation and
closure, among other best practices serve to prevent to the greatest extent possible the types of
impacts to communities, environment, natural resources and public health that could dampen the
interests of potential tourists.
Conclusion
Due to a lack of data regarding the coexistence of tourism and drilling, the possible impacts to tourism
activity in Western Maryland were not quantifiable. Nor was it feasible to separate out the effect on
tourism of other factors, such as the recent national recession or the effect of other extractive
industries, from the effect of the unconventional shale gas development industry. Perceived decline in
environmental amenities and access to tourism related services such as destinations and lodging is of
great concern to the businesses and residents of Western Maryland. Careful planning, regulatory
control and management of unconventional gas well development are key to maintaining the tourism
industry.
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R.
Emergency Response Capacity
Background
Information about traffic accidents and incidents at well pads in other states indicates that additional
burdens fall on emergency response personnel when unconventional natural gas development occurs in
a region. Concern has been expressed about the ability of Western Maryland communities to manage
the additional demands.
Data and Discussion
The following information about Allegany County’s fire and emergency response capability appears on
the webpage for the County’s Department of Emergency Services at
http://gov.allconet.org/DES/Fire_Ambulance_Companies.htm:
Allegany County is served by 13 volunteer ambulance companies and one career
ambulance service. Advanced life support is provided by 13 of the 14 ambulance
companies and basic life support is provided by the remaining one. There are also two
commercial ambulance companies serving Allegany County. The Maryland State Police
medical helicopter, Trooper 5, is stationed at the Cumberland Regional Airport in nearby
Wiley Ford, West Virginia and provides advanced life support.
The area is served by the Western Maryland Regional Medical Center, the designated
area wide trauma center, 12500 Willowbrook Road, Cumberland.
Emergency personnel receive training provided by the Maryland Fire and Rescue
Institute and the Regional Emergency Medical Services Council. Personnel are certified
through the Maryland Institute for Emergency Medical Services System.
The following additional information is provided in the Allegany County Hazard Mitigation Plan Update
(2012), available online at
http://gov.allconet.org/DES/docs/Allegany%20County%202012%20Hazard%20Mitigation%20Plan%20U
pdate.pdf. The municipal and non-municipal fire companies and rescue squads are staffed by
volunteers, except for Cumberland, which has a paid fire department. The County has established a
Special Operations Team to assist local fire and rescue organizations; this team has training in hazardous
materials incident response, swiftwater search and rescue, collapse rescue, high-angle rescue, confined
space rescue and search and rescue. The County’s 2008 Allegany County, Maryland Hazardous Materials
Emergency Response Plan details the procedures to be utilized during a hazardous materials incident.
The County has a HazMat Team that can be called to respond to incidents.
Garrett County’s webpage provides the following information about emergency management at
http://www.garrettcounty.org/emergency-services:
Garrett County Emergency Management develops and maintains plans for emergency
response, including the County Emergency Operations Plan, Hazard Mitigation,
Hazardous Materials Response Plan. Responsible for coordinating evacuation and
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sheltering of populations affected by disaster. Coordinates with other public safety
response entities to ensure a timely and appropriate response to any and all
emergencies.
July 13, 2011 Garrett County's 911 center consolidated with the Garrett County Sheriff's
Office, which placed the 911 communications officers for fire rescue and EMS with the
law enforcement communications officers in one brand new center. This move involved
training and certification for all communications officers in Emergency Medical Dispatch
and Emergency Police Dispatch, which enabled the communications officers to work
more efficiently in all circumstances.
911 Public Safety Answering Point / Police, Fire & Rescue Communications receives and
processes all emergency 9-1-1 calls for assistance, including fire, EMS, and police. Once
sufficient information has been gathered, the call-taker must alert the appropriate
response agencies, maintain communications, and log all pertinent information.
Additionally, all staff must maintain nationally certified Emergency Medical Dispatch
training which provides emergency medical instructions to callers, as well as Emergency
Police Dispatch training.
The web page also identifies five trained emergency medical services providers who are associated with
the local fire departments and rescue squads. The County is currently revising its Hazard Materials Plan,
which specifically assigns roles and responsibilities of all agencies and departments involved in a
hazardous materials accident, whether it is from a fixed facility or as a result of a transportation
accident. The County has a Local Emergency Planning Committee, which is responsible for development
and oversight of the plan. This committee is made up of individuals representing response agencies,
business and private citizen leaders.
With the exception of fires on the well pad and well blowouts, incidents involving the oil and gas
industry are not significantly different from other industrial accidents and hazardous materials
incidents. Even an accident involving a worker injury high on a drill rig – a high-angle rescue – has been
the subject of training of the local emergency response personnel.
Fires and blowouts at the well pad require specialized training, and local emergency response personnel
would be expected only to remove the injured, establish a perimeter, and perhaps assist with an
evacuation, if it were deemed necessary. Nevertheless, such incidents would likely require the presence
of police or emergency response personnel for an extended period of time. These incidents, if they
cannot be managed by the workers on site, require specialized contractors that are on call by the oil and
gas industry. The State will require that the operator shall identify specially trained and equipped
personnel who could respond to a well blowout, fire, or other incident that personnel at the site cannot
manage. These specially trained and equipped personnel must be capable of arriving at the site within
24 hours of the incident.
The topic of emergency response was discussed at the Advisory Commission meeting of March 10, 2014.
Thomas Levering, Director of MDE’s Office of Emergency Preparedness and Planning, and John Frank,
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Director of Garrett County Emergency Services, were present and discussed the ongoing activities to
plan for gas development and the need for training and equipment. At the November 25, 2014,
meeting, a discussion of health care infrastructure touched on ambulance and fire fighting capacity. It is
becoming increasingly difficult to staff these services with volunteers, and the counties have developed
strategies to address the challenges. Ultimately, however, it may be necessary to establish paid
positions to ensure an acceptable level of service for the residents.
Conclusion
Emergency response presents a challenge because volunteers staff most of those services in Allegany
and Garrett Counties, and because of the lack of a dedicated funding source. The Departments’ Best
Management Practices Report requires that: “Operators shall, prior to commencement of drilling,
develop and implement an emergency response plan, establish a way of informing local water
companies promptly in the event of spills or releases, and work with the governing body of the local
jurisdiction in which the well is located to verify that local responders have appropriate equipment and
training to respond to an emergency at a well.” This requirement will ensure that the well operators will
support local authorities to ensure emergency response resources are in place to protect the workers
and the public.
S.
Health Infrastructure Capacity
Background
Considerable concern has been expressed about the impact of the arrival of many additional gasfield
workers on the public health infrastructure. Newspaper articles and internet sources have reported that
levels of crime, sexually transmitted infections (STIs), mental illness and substance abuse have risen in
areas where there was a large influx of workers into rural areas. Similar sources have reported that
hospitals have difficulty dealing with the number of emergency room visits and suffer financially
because many of the transient workers lack health insurance.
Data and Discussion
Garrett County and part of Allegany County have been recognized to be medically underserved areas.
MIAEH (2014) reported that “Allegany County is a designated Health Professional Shortage Area (HPSA)
for primary care for low-income populations, mental health care for Medical Assistance populations,
and dental care for Medical Assistance populations. Allegany County has a critical need for specialty
providers including vascular surgery, urology, as well as dentists willing to provide care for adults with
no insurance or Medical Assistance. Garrett County is a designated HPSA for primary and mental health
care, and dental care for Medical Assistance populations.”
According to the University of Maryland School of Public Health (MIAEH, 2014), “A handful of studies
that have been conducted indicate that extractive industry workers place similar demands on health
care infrastructure as local residents, with an increased demand on emergency department services.”
(Citations omitted.) Their study, however, did not quantify the increased demand, other than to
compare the number of new workers to the existing permanent population. No mention was made of
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the large number of vacationers who come to the Garrett County area during the summer and the ski
season.
To estimate the burden on emergency, urgent care, and trauma care, one can refer to statistics supplied
by the United States Government through the Centers for Disease Control and Prevention (CDC) and
National Institute for Occupational Health and Safety. The annual occupational fatality rate for oil and
gas workers has historically been higher than those for workers generally. The CDC reported the
averages for the period 2003-2009 as follows:
Category
Oil and Gas Workers
All US Workers
Fatalities per 100,000 full time workers
27.5
3.9
Table 18. Annual occupational fatality rate
Source: CDC, 2012.
The leading causes of deaths for oil and gas workers included highway motor vehicle crashes (29
percent); workers being struck by tools or equipment (20 percent); explosions (8 percent), workers
caught or compressed in moving machinery or tools (7 percent), and falls to lower levels
(6 percent) (CDC, 2012).
In contrast, the non-fatal injury rate has been lower than the United States average.
Category
All oil and gas job extraction
Oil and gas support activities
Oil and gas drilling
All US workers
Non-fatal injuries per 100 full time workers
1.2
1.9
3.3
3.5
Table 19. Annual nonfatal injuries rate
Source: CDC, 2012
The Regional Economic Studies Institute at Towson University, in an evaluation of the economic impact
of Marcellus Shale gas development, considered two potential development scenarios of different
intensities (RESI, 2014). For each scenario, the number of direct jobs in the oil and gas industry and the
number of “spinoff” jobs were projected for Allegany County and Garrett County. The peak year for
Garrett County is 2021 and the peak year for Allegany County is 2024.
County
Allegany
Garrett
Peak year for jobs
2024
2021
Direct jobs
442.5
1185
Spinoff jobs
465.5
1239.7
Table 20. Numbers of jobs in peak year
Source: Revised RESI study, Figures 97 and 108
Applying the fatality rate of 27.5 per 100,000 workers to oil and gas workers and the rate of 3.9 per
100,000 workers in spinoff jobs yields the following projection for the peak year:
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County
Allegany
Garrett
Fatalities (direct jobs, peak year)
0.12
0.33
Fatalities (spinoff jobs, peak year)
0.02
0.05
Table 21. Number of fatalities in peak year
Because the number of jobs in each category (all oil and gas extraction, oil and gas support activities, oil
and gas drilling) is not known, for purposes of estimating the number of nonfatal injuries, the highest
rate, 3.3 per 100 full time workers, will be applied to the direct jobs. The spinoff jobs are assigned the
rate for all United States workers.
County
Allegany
Garrett
Injuries (direct jobs, peak year)
14.6
39.1
Injuries (spinoff jobs, peak year)
16.3
43.4
Table 22. Number of nonfatal injuries in peak year
In the peak year, assuming all the direct and spinoff jobs were filled by workers moving in from out of
County, the number of direct and spinoff jobs for Allegany County would represent an increase of 1.2
percent over the 2010 census population of 75,087. For Garrett County, the number of workers in the
peak year, assuming all the jobs were filled by persons moving into Garrett County from elsewhere,
would represent an increase of 8.1 percent over the 2010 census population of 30,097. Garrett County,
however, experiences an influx of non-residents throughout the year. The number of person-trips was
estimated in a tourism study as exceeding 1.1 million person-trips from August 2008 to July 2009 (Deng
et al., 2010):
Seasonal person-trips are estimated at 402,388 for summer, the largest of all seasons,
accounting for 36.0% of total person-trips for the survey year. Winter season was also
popular with the total person-trips being 310,733, followed by fall (240,315 persontrips) while spring season was the least attractive with the total person-trips being
164,308.
On September 25, 2014, Rodney B. Glotfelty, Garrett County health Officer, provided written testimony
to the Garrett County Marcellus Shale Advisory Committee on the MIAEH report. Mr. Glotfelty did not
agree with the conclusions drawn by the authors of the study, who predicted that “an increase in health
care utilization, regardless of whether workers are insured or uninsured, would strain the existing
healthcare infrastructure, likely leading to decreased quality, availability, and access to services”
(MIAEH, 2014). He wrote:
While our health system may be challenged in serving an influx of relatively young
people working in the gas development industry, in general we feel it is resilient
enough to meet the increased demand without jeopardizing public health. In late
fall or early winter, a new satellite office of Mountain Laurel Medical Center (FQHC)
will be opening in Grantsville. This means additional providers will be recruited to
serve Garrett County residents. The new CEO of the hospital has also been very
aggressive in recruiting new physicians and services to the community and in
developing strategic planning processes that can allow the hospital to rapidly
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respond to changing conditions. Finally, the Garrett and Allegany Health
Departments provide mental health, substance abuse, and STI clinics that can be
augmented to meet increased need. There will also be many opportunities to
integrate mental health services with somatic care in the next few years in local
provider offices. Certainly the pace of natural gas development in Garrett County, if
it ever occurs, will determine how rapidly changes to the delivery system must be
made.(Glotfelty, 2014).
Mr. Glotfelty gave a presentation to the November 25, 2014, Advisory Commission meeting and
reiterated his view that the health care system is sufficiently resilient to accommodate new workers in
the gas industry without compromising the level of health care delivery to the residents.
A different challenge is likely to be faced by the Environmental Health Division of the County Health
Departments. If drilling does occur in Western Maryland, there will be pre-drilling sampling as well as
ongoing monitoring of drinking water wells in the vicinity of the well pad. Pre-development sampling
may identify wells that have existing contamination. In a recent background study in North Carolina, the
USGS found that “Concentrations of nitrate, boron, iron, manganese, sulfate, chloride, total dissolved
solids, and measurements of pH exceeded federal and state drinking water standards in a few samples.
Iron and manganese concentrations exceeded the secondary (aesthetic) drinking water standard in
approximately 35 to 37 percent of the samples” (USGS, 2014). Citizens having questions about the
testing results are likely to contact the Environmental Health staff in their counties. In addition,
residents that perceive any change in the appearance, taste or odor of their well water may request that
the Counties test their water. Analyzing water samples can be expensive and responding to citizen
complaints can be very time consuming for the staff.
Conclusion
The burden on emergency, urgent care, and trauma care will likely increase if unconventional gas
development proceeds in Western Maryland, but the system is likely to be resilient enough to meet the
increased demand without jeopardizing public health.
T.
Health Surveillance
Background
MIAEH (2014) noted that the combination of environmental and psychosocial stressors can lead to
effects that are cumulative, and recommended monitoring to verify the effectiveness of primary
prevention actions and improve them as necessary. The three recommendations included initiation of a
birth outcomes surveillance system, a longitudinal epidemiologic study of irritant symptoms that have
been associated with UNGDP, and development of a funding mechanism for public health studies.
Data and Discussion
MIAEH did not present baseline data on birth outcomes or on symptoms in this population. As noted in
their report, there was not an opportunity to conduct a baseline health survey of the population that
could have answered some or all of these questions. Some of the data are available through local health
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departments and the Department of Health and Mental Hygiene, but have not been compiled for these
purposes. The MIAEH report acknowledged that some funding might be achieved through collaboration
with academic researchers, but also recommended exploration of alternative funding mechanisms.
Conclusion
Recommendations related to health monitoring are not within the scope of the Executive Order or the
permitting process, but there may be opportunities for public health agencies, working with academic
institutions, to explore means to address them, including establishment of baseline data.
U.
Waste and Wastewater Disposal
Background
Solid wastes produced at well sites include drill cuttings, spent drilling muds, sludges, brine scales, and
other solid wastes. These wastes need to be disposed of (on-site or off-site), recycled, or beneficially
reused.
After a well is hydraulically fractured, some portion of the hydraulic fracturing fluid, called flowback,
moves up the wellbore to the surface. Other water that is produced from the well after the initial
flowback is termed produced water. These are the major types of wastewater generated at a drill site.
Wastewater associated with shale gas extraction can contain high levels of total dissolved solids (TDS),
fracturing fluid additives, metals, and naturally occurring radioactive materials. Typically, flowback
contains significant concentrations of dissolved sodium, calcium, chloride, barium, magnesium,
strontium, and potassium. It can also contain volatile organic compounds. There are a few options for
managing this wastewater, including underground injection in regulated Class II injection wells,
pretreatment followed by further treatment by a sewage treatment plant, evaporation/crystallization,
and recycling.
Data and Discussion
One option for solid waste is on-site disposal, which is the permanent placement of solid drilling waste
into a pit within the disturbed area used for HVHF operations. Once filled, the area is reclaimed to
prevent erosion. As part of Maryland’s Best Management Practices, it will be required that the cuttings
and drilling mud should be tested for radioactivity, as well as other contaminants, including sulfates and
salinity, before disposal. If the cuttings show no elevated levels of radioactivity, and meet other criteria
established by MDE, onsite disposal of the cuttings could be allowed. Current regulations provide “Land
farming of cuttings shall be permitted only on approval from the Department and shall require: (1) Soils
analysis before site preparation; (2) Cuttings analysis as directed by the Department; and (3) Post land
farming soils analysis.” The Department has not set criteria in advance, but MDE has significant
experience with land application of materials such as sludge from wastewater treatment plants. The
criteria could be site-specific.
Solid wastes may also be disposed of in landfills. Maryland’s nonhazardous waste landfills include liners
designed to prevent the release of hazardous constituents from the landfills. The landfills are also
83
required to do routine groundwater monitoring to detect any releases. Permits for the landfills establish
limitations on what the landfills may accept for disposal.
Recycling of gas development wastewaters, and reusing them for hydraulic fracturing, is the most
environmentally sound method, and the method that operators have been moving toward. Maryland’s
Best Management Practices include a recommendation that, unless the permittee can demonstrate that
it is not practicable, the permittee be required to recycle not less than 90 percent of the flowback and
produced water and carry out that recycling on the pad site where the waste was generated.
Maryland’s Best Management Practices also recommend that Maryland should not allow the discharge
of any untreated or partially-treated brine, or residuals from brine treatment facilities, into surface
waters. Federal regulations already prohibit the direct discharge of these materials into surface waters.
Indirect discharge is the introduction of pollutants from a non-domestic source into a publicly owned
wastewater treatment system, often called a Publicly Owned Treatment Works (POTW). Indirect
discharges to POTWs are subject to General Pretreatment Regulations, which provide that a user of a
POTW may not introduce into a POTW any pollutant(s) that cause a POTW to violate its own discharge
limitations or that disrupt the POTW, its treatment processes or operations, or the processing, use or
disposal of its sludge, and thereby cause the POTW to violate its permit.
There are currently no national standards specifically for the indirect discharge of gas exploration and
development wastewaters. 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, locations in Maryland suitable for siting injection wells
may be very limited. Because it is not likely that Class II wells will be located in Maryland, the Best
Management Practices deferred any consideration of this matter unless and until someone proposes to
apply for a permit for a Class II injection well.
Finally, in order to assure that all wastes and wastewater are properly treated or disposed of, the Best
Management Practices require permittees to keep a record of the volumes of wastes and wastewater
generated on-site, the amount treated or recycled on-site, and a record of each shipment off-site. For
shipments off-site, the record would have to include information on the type of waste, the volume or
weight of waste, the identity of the hauler, the name and address of the facility to which the waste was
sent, the date of shipment, and confirmation that the full shipment arrived at the facility. The records
would be maintained by the permittee for at least three years, and MDE could audit them during site
inspections or otherwise.
Conclusion
Wastes produced at well sites can contain many contaminants that require proper management,
including dissolved solids, fracturing fluid additives, metals, naturally occurring radioactive materials,
84
dissolved sodium, calcium, chloride, barium, magnesium, strontium, potassium, and volatile organic
compounds.
Maryland’s Best Management Practices, as well as current state and federal regulations, ensure that the
drilling wastes are managed properly, and that detailed records are kept for all wastes generated,
treated or recycled, or shipped off-site.
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Section V: Information Gaps
High volume hydraulic fracturing of horizontal boreholes to stimulate the production of oil and gas from
less permeable (“tight”) formations is a relatively recent development, dating back to around 2006 or
2007. While many tens of thousands of hydraulic fracturing jobs have been carried out throughout the
United States, careful analysis of the potential negative consequences of this industrial activity has only
just begun. Peer reviewed reports addressing questions about possible environmental contamination or
potential public health impacts have only begun to appear in the literature during the last three to four
years. As a result, the Departments and the Advisory Commission recognize a number of gaps in our
understanding that need to be addressed.
Lack of site specific geological and hydrogeological data
Site specific geological data are required to design and engineer a safe, productive gas well. Much of the
required information will be collected by the operators during the exploration phase, relying heavily on
3D seismic surveys to identify the depth and structure of geological formations in the subsurface. These
surveys may be capable of identifying faults and other structures that could be problematic if they
provide pathways for fracturing fluids under pressure to migrate beyond the target formation, or if they
pose any risk of minor earthquakes caused by hydraulic fracturing. Additional essential geological data
will result from drilling a pilot hole, enabling the operators to analyze drill cuttings and to record well
logs that delineate the thickness and maximum depth of fresh groundwater aquifers. Results of these
geological investigations will be reported to MDE as a part of the permitting and reporting
requirements.
Beyond the thickness and maximum depth of fresh groundwater at each drilling site, additional
hydrogeological data are very important to collect. Does the site contain unconsolidated alluvium22 or
colluvium23? How thick is the soil profile and how deep is the water table? How deep is the transition
to a fractured hard rock groundwater aquifer, and what are the hydrogeological properties of each
surface and subsurface soil/rock type? Finally, what is the nature of subsurface hydraulic gradients at
the site – in which direction and how fast does groundwater flow? Answers to these questions are
critical for a solid understanding of the potential impacts of an accident or a well failure.
Location of historic gas wells
Media reports from Pennsylvania, which has a long history of numerous oil and gas wells, suggest that
historic wells may frequently be abandoned, improperly plugged, and not precisely located in state
databases. Improperly abandoned wells may leak methane to the atmosphere. An abandoned well that
is not properly plugged could serve as a conduit for vertical transport of hydraulic fracturing fluid from
the target formation to the surface. Something like this has happened on occasion in the vicinity of
waste water injection wells (Lustgarten, 2012. Scientific American, “Are fracking wastewater wells
poisoning the ground beneath our feet? June 21, 2012). For this reason, the location and structural
22
Alluvial soil is made up of grains that have been transported and deposited by running water, such as streams.
Colluvial soil is soil formed from the weathering of bedrock and then moved downslope by rainwash, sheetwash,
or gravity.
23
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state of historical gas wells in the region of a drill site, including all of the property overlying the
horizontal laterals, must be determined.
Wet vs. dry gas
Based upon regional geological studies and modeling, the Marcellus Shale beneath Maryland is expected
to contain dry gas – methane with little or no percentage of larger hydrocarbons such as ethane or
propane. However, this expectation is untested. Should the Maryland Marcellus contain wet gas, then
estimates of the potential for air emissions especially during well completion may need to be
reevaluated.
Technical data gaps
The technology of gas development is constantly changing. Additional types of non-potable water may
be suitable for hydraulic fracturing. Wastewater treatment technologies may become more effective or
less expensive. As operators and service companies work to improve zonal isolation with casing and
specially formulated cement, the rate of well failure and methane migration should be tracked so the
most effective technology can be identified. It would be helpful to learn which methods of integrity
testing and monitoring for well failure and methane migration are best.
Data on health and community impacts
Additional studies on the health risks of persons living near unconventional gas wells are necessary.
These could include both research studies and public health surveillance to monitor the success of the
best practices and potential need for improved practices or enforcement. Although the small population
makes it unlikely that an epidemiological study of rare conditions would have sufficient statistical power
to provide meaningful results without many years of follow-up, surveillance and appropriately designed
studies could identify clusters of symptoms and increased rates of more common health conditions.
Reports of acute health effects due to periodic spikes in ambient air pollution levels should also be
investigated; the data on the frequency and magnitude of such spikes and whether they are associated
with health impacts is lacking.
Seismic information
Currently, the Maryland Seismic Network consists of a single seismometer at Soldier’s Delight Natural
Environment Area in Baltimore County. Although perceptible earthquakes are very rarely associated
with hydraulic fracturing, establishing additional permanent seismometers in Western Maryland would
improve coverage of the State and reassure the public.
87
Section VI: Conclusions and Recommendations
The purpose of the Marcellus Shale Safe Drilling Initiative is to help State policymakers and regulators to
determine whether and how gas production in the Marcellus Shale in Maryland can be accomplished
without unacceptable risks of adverse impacts to public health, safety, the environment and natural
resources. Over the last three and a half years, the Departments, in consultation with an Advisory
Commission, have been assembling and evaluating information on these questions. It is the judgment of
the Department of the Environment and the Department of Natural Resources that, provided all the
best practices are followed and the State is able to rigorously enforce compliance, the risks of Marcellus
Shale development can be managed to an acceptable level.
The best practices and this conclusion are based on the assumption that the natural gas in the Marcellus
Shale in Maryland will be dry gas, with little or no liquid hydrocarbons. If this assumption is not correct,
it may be necessary to reevaluate the air pollution issues before proceeding. In this case, the applicants
should, at a minimum, be required to model air pollution from the site and perform an Air Toxics review
as part of the application process.
The following steps should be taken if Marcellus Shale gas development is to proceed in Maryland.
Confirm effectiveness of best practices.
The Departments are mindful of data and reports from other states about elevated levels of pollutants
in the air, contaminated groundwater, and spikes in air pollution that cause acute effects. In most cases,
the data and reports were from areas with rapid and intensive gas development, some in jurisdictions
where government regulation was not stringent and enforcement was not rigorous. It would be prudent
to undertake intensive monitoring of the initial shale gas development projects in Maryland in order to
determine whether contamination is occurring. If it is, additional steps must be taken to protect the
public.
Monitor air, groundwater and surface water.
The Air and Radiation Management Administration of MDE intends to convene a stakeholders group to
evaluate appropriate locations, methods, and frequency for air monitoring. Monitoring of groundwater
to detect stray methane or other contamination will continue throughout the life of the well. As a
component of any individual permit, an applicant is required to conduct two-years of baseline surface
and groundwater monitoring before any drilling can occur. The permit will require continued monitoring
of selected locations to ensure that any deviations from baseline conditions resulting from drilling are
identified so as to be appropriately addressed.
Use the CGDP to protect the environment and public health.
A mandatory Comprehensive Gas Development Plan is the only means to address landscape level
impacts. It can direct development to areas where harm is less likely. Development and approval of the
plan need not be onerous or unduly time-consuming.
88
Reduce the amount of truck traffic.
The elevated risk due to the volume of truck traffic is of concern. Companies should be required
whenever possible to establish centralized fresh water storage facilities from which water can be
delivered to well pads by aboveground hoses or pipes. Enforcement of weight limits, safety regulations,
and sound limits will be necessary to reduce the impact of truck traffic.
Adopt new regulations.
New regulations must be adopted. The existing regulations for oil and gas development in Maryland are
out of date and unsuitable for horizontal drilling and high volume hydraulic fracturing. In fact, the
existing regulations prohibit the now-common shale gas practice of constructing multiple wells on a
single pad because currently “The Department may not issue a permit to drill and complete a gas well
closer than 2,000 feet to an existing gas well in the same reservoir unless the Department is provided
with credible geologic evidence of reservoir separation to warrant granting a spacing exception”
(COMAR 26.19.01.09 E). Codifying the recommended practices in regulations will not prevent the
Department from mandating safer technologies, because by statute, Environment Article, § 14-110
(a)(2), “The Department may place in a permit conditions which the Department deems reasonable and
appropriate to assure that the operation shall fully comply with the requirements of this subtitle, and
provide for public safety and the protection of the State's natural resources.”
Since 2010, the Department of the Environment has been authorized by Environment Article §§ 14-105
and 14-123, to set and collect permit fees in an amount necessary to administer and implement its gas
and oil program, including 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.
The Department had not acted to set the fee because it was not possible to estimate the magnitude of
the need until the completion of this report. To ensure proper inspection and enforcement, it is
imperative that the fee be set at an appropriate level to support the Comprehensive Gas Development
Plan process, review the detailed plans submitted for each well permit, and adequately monitor and
enforce compliance with the permit.
Enact legislation.
The enforcement provisions of the existing statute should be revised. The Department’s administrative
remedies are limited to issuing administrative orders. The Department can go to court to seek an
injunction to enforce compliance. Currently, a willful violation is considered a misdemeanor punishable
by a fine up to $50,000 and the costs of damages resulting from a spill or other violation. The statute
89
provides no other penalties. The addition of administrative and civil penalty provisions with appropriate
fines would help deter violations.
In addition to updating the regulations and strengthening the enforcement provisions, the Departments
strongly recommend that the legislature pass a state-level severance tax. The severance tax revenue
should be deposited into a Shale Gas Impact Fund to be used for continuing regional monitoring and to
address impacts of gas exploration and production that cannot be attributed to a specific operator, or
for which there is no solvent responsible entity. The Departments also recommend that Maryland adopt
an act to protect the rights of surface owners. The Departments supported the severance tax bill in the
2014 session, and the Departments and the Advisory Commission have advocated for a surface owners
protection act since late 2011.
Manage adaptively.
New technologies and additional information about the impacts of shale gas development are
constantly emerging. Maryland must follow developments in the field and be prepared to adapt with
new regulations or new permit provisions.
90
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Appendix A: Members of the Advisory Commission
Chair
David Vanko, Ph.D., Dean of The Jess and Mildred Fisher College of Science and Mathematics at Towson
University
Members
State Senator George C. Edwards (District 1)
The Honorable Heather R. Mizeur (State Delegate, District 20, 2007-2015))
The Honorable James M. Raley (Garrett County Commissioner, 2010-14)
The Honorable William R. Valentine, Allegany County Commissioner
The Honorable Margaret “ Peggy” Jamison, Mayor of Oakland
Shawn Bender, Division Manager at the Beitzel Corporation and past President of the Garrett County
Farm Bureau
Ann Bristow, Ph.D., Savage River Watershed Association
Stephen M. Bunker, Director of Conservation Programs, Maryland Office of the Nature Conservancy
Jeffrey Kupfer, Esquire, formerly Senior Advisor, Chevron Government Affairs
Clifford S. Mitchell, M.D., Director, Environmental Health Bureau, DHMH
Dominick E. Murray, Secretary of the Maryland Department of Business and Economic Development
Paul Roberts, Garrett County resident and co-owner of Deep Creek Cellars Winery
Nicholas E. Weber, Ph.D., past Chair of the Mid-Atlantic Council of Trout Unlimited
Harry Weiss, Esquire, partner at Ballard Spahr LLP
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Appendix B: Comments and Concerns
The Advisory Commission agreed that the existing regulations for oil and gas wells in Maryland are not
adequate to regulate the horizontal drilling and high volume fracturing that gas production from the
Marcellus Shale involves. Beyond that basic position, there was no unanimity, although the majority of
the Commissioners who expressed an opinion on the recommendations said that they could support all
or most of the recommendations, and that the reports contained valuable information that should be
considered by the incoming Administration.
Some organizations and individuals oppose shale gas development because they oppose any additional
production of fossil fuels regardless of how safely it can be done, or because they do not believe the
short term economic benefits will be worth the potential long-term consequences to the environment
and the economy. They advocate a complete ban.
Some Commissioners and some members of the public argued strongly that our knowledge base is
inadequate to answer the question of whether and how gas production in the Marcellus Shale can be
carried out without unacceptable risks. The paucity of data on health effects and the absence of long
term or epidemiological studies are often cited. These Commissioners and members of the public urged
that the Departments apply the precautionary principle and declare that it is premature to make the
decision to allow this type of gas development to proceed. They recommended a moratorium so that
additional studies could be done.
One Commissioner and members of the public urged the Departments to adopt greater setbacks from
private drinking water wells – 3,281 feet (1 km) rather than 2,000 feet. They cited a published article and
noted that the Departments’ own risk assessment indicated that 3,281 feet would be more protective
than 2,000 feet.
Others expressed the opinion that enough is known to make a decision. They concluded that, with
stringent regulations, good monitoring and robust enforcement, high volume hydraulic fracturing poses
no unacceptable risks and should be allowed in Maryland. They also advise an adaptive approach for
permitting gas development that is responsive to new information as it emerges.
Some Commissioners, representatives of the industry and others view the Department’s
recommendations as unnecessarily stringent and time consuming. They object primarily to the
mandatory nature of the Comprehensive Gas Development Plan (CGDP) and the requirement for two
years of baseline monitoring.
Other criticisms of the proposals are that the setbacks are arbitrary and that there is no provision for
waivers. The Department retains the power to impose more stringent measures in permits, but not to
waive regulatory provisions. Some citizens expressed the fear that a waiver provision could eviscerate
the protections they desire. Allowing a waiver based on the consent of the person who would otherwise
be protected, however, seemed problematic in light of the Attorney General’s advice on Senate Bill 370,
"Garrett County - County Commissioners – Industrial Wind Energy" in 2013.
98
Several Commissioners and members of the public emphasized the need to ensure that adequate
funding will be available to implement the revised gas well program and to enforce the new regulations.
Some also advocated that administrative and civil penalties be authorized, and that criminal sanctions
be imposed.
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Appendix C: Best Practices
The best practices identified in this Appendix formed the basis for the analysis, findings and conclusions
in this report. Unless these practices, or others equally protective of public health, safety, the
environment and natural resources, are followed, the conclusions in this report should be reevaluated.
The practices were developed specifically for the Marcellus Shale region of Western Maryland and may
not be suitable for other shale deposits. Additional information about the best practices and definitions
of some terms can be found in the Interim Final Best Practices Report.
A Mandatory Comprehensive Gas Development Plan (CGDP)
1. The purpose of the CGDP is to identify travel routes and the locations for well pads, access
roads, pipelines and other ancillary facilities that
a. Avoid, to the extent possible, adverse site-specific and cumulative impacts to public
health, the environment, the economy and the people of Western Maryland;
b. Minimize the adverse impacts that cannot be avoided; and
c. Mitigate the remaining impacts.
2. Except for a limited number of exploratory wells, no one may apply for a permit to drill an oil or
gas well until the applicant has first obtained the approval of a CGDP and the application must
be consistent with the approved CGDP.
3. The CGDP should address as much as possible of a company’s planned development, but no less
than the development expected in the next five years.
4. An approved CGDP will remain in effect for ten years, but one renewal for an additional 10 years
may be granted by MDE if the resource information is updated, and the locations approved in
the initial CGDP are not prohibited under any more stringent location restrictions or setback
requirements enacted after the approval of the initial CGDP.
5. Without an approved CGDP, one exploratory well may be permitted, provided it meets all other
regulatory requirements, within a circular area having a radius of 2.5 miles centered at the
exploratory well.
Location Restrictions and Setbacks
1. No oil or gas well with lateral drilling and hydraulic fracturing shall be permitted unless the there
is a separation of at least 2,000 vertical feet between the deepest fresh water aquifer and the
target formation.
2. No surface disturbance for pads, roads, pipelines, ponds or other ancillary infrastructure shall be
permitted on State-owned land, without the consent of DNR.
3. No well pad may be permitted on land with a slope, before grading, of greater than 15 percent.
4. No well pad may be permitted within the watersheds of any of the following reservoirs:
a. Broadford Lake
b. Piney Reservoir
c. Savage Reservoir
5. The edge of disturbance of a well pad shall be at least
a. 1,000 feet from the boundary of the property on which the well is to be drilled.
b. 450 feet from the edge of an aquatic habitat.
100
c. 600 feet from special conservation areas.
d. 300 feet from a cultural or historical site, State or federal parks, trails, wildlife
management areas, wild scenic rivers, and scenic byways.
e. 1,000 feet of known caves.
f. 750 feet on the downdip side of a limestone outcrop.
g. 1,000 feet from any occupied building, school or church.
h. 1,000 feet of a wellhead protection area for a public water system for which a wellhead
protection area has been delineated.24
i. 1,000 feet of the default wellhead protection area for public water systems for which a
wellhead protection area has not been officially delineated. [For public water systems
that withdraw less than 10,000 gpd from fractured rock aquifers the default SWPA is a
fixed radius of 1000 feet around the water well(s).]
j. 2,000 feet from a private drinking water well.
k. Within an area defined as all lands at an elevation equal to or greater than the discharge
of a spring used as the source of domestic drinking water by the resident(s) of the
property on which the spring is located, not to exceed 2,500 feet unless the Department
approves an alternative based on the delineation of recharge area of the spring.
6. The vertical and horizontal boreholes may not be within 1320 feet of any historic oil or gas well
(this does not prohibit new horizontal boreholes from being located within 1320 feet from each
other).
7. The setback restrictions for well pads also apply to all gas development activities that result in
permanent surface alteration that would negatively impact aquatic habitat, special conservation
areas, cultural and historical sites, State and federal parks, forests and trails, wildlife
management areas, wild and scenic rivers and scenic byways.
Environmental Assessment
With the application for a permit to drill a well, the applicant must submit an Environmental Assessment
that satisfies guidance issued by the department, including two years of baseline monitoring in the
vicinity of the well pad. Baseline monitoring must be completed before any site preparation or
construction is done at the site of the planned well pad. The applicant must also perform a geological
investigation of the area covered by the CGDP, to help identify underground features such as fractures
or faults.
Performance Standards and Minimum Requirements
In an application for a permit to drill a well, the applicant shall submit detailed plans for construction
and operation of the well that meet or exceed the following performance standards and minimum
requirements. In preparing the plan, the applicant shall consider relevant industry standards and
24
The draft version of this report erroneously included a 1,000 feet setback from any Source Water Protection
Area for a public water system. Surface water intakes for public water systems are protected by a setback of 450
feet and by provisions requiring gas well operators to contact downstream public water systems promptly in the
event of a spill.
101
practices as well as standards issued by the American Petroleum Institute. An approved plan shall be
incorporated by reference into the well permit.
1. Sediment and erosion must be controlled in accordance with State law for all construction,
including the well pad, ponds, access roads and pipelines.
2. There shall be no discharge from the pad as long as any fuels or chemicals are present on the
pad.
a. The pad shall be constructed with an impermeable liner (maximum hydraulic
conductivity 10-7 cm/sec) and berms so that it is capable of containing, at a minimum,
the 25-year, 24-hour precipitation event.
b. 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.
c. Stormwater collected from the pad may be used for hydraulic fracturing but, prior to
use, it must be stored in tanks and not in a pit or pond.
d. All liquids (except fresh water) shall be stored in watertight, closed tanks or containers
with secondary containment capable of holding the volume of the largest tank or
container. If the tanks may emit methane or VOCs and are vented to the environment
must have pollution control equipment to destroy or capture methane and VOCs.
e. After all fuel and chemicals are removed from the site, stormwater will be managed in
accordance with State law.
3. Only fresh water may be stored in ponds, and the ponds must be properly constructed and
lined.
4. Access roads shall be constructed and operated to allow safe passage of vehicles accessing the
site and shall include stormwater controls and dust control.
a. The design, construction and maintenance of unpaved roads be at least as protective of
the environment as the standards adopted by the Bureau of Forestry of the
Pennsylvania Department of Conservation and Natural Resources.
b. The standards are contained in Guidelines for Administering Oil and Gas Activity on State
Forest Lands.
5. Travel for all heavy truck traffic to or from the well pad or to or from centralized facilities serving
the well pad shall be planned and implemented to minimize conflicts with the public. The plan at
a minimum, shall
a. Avoid truck traffic during times of school bus transport of children to and from school
locations.
b. Not interfere with public events or festivals.
c. Minimize truck traffic in residential areas
d. Minimize conflict with public uses such as hunting and fishing.
6. Drinking water aquifers must be protected from contamination during drilling.
a. 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,
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shall be drilled with air, fresh water, a freshwater based drilling fluid, or a combination
of the above.
b. Only additives approved under SNF/ANSI Standard 60: Drinking Water Chemicals may be
used for drilling through fresh water aquifers.
7. Wells shall be drilled, cased and cemented to effectively isolate the borehole from the
surrounding formations and prevent the migration of gas or liquids into or out of the casing and
the formation.
a. At least one pilot hole must be drilled from a well pad before drilling any well from that
pad that will include directional drilling to assist in the identification of geological
features, underground voids, gas- or water-bearing formations, and the lowest fresh
water aquifer.
b. The applicant for a drilling permit must submit a plan for MDE’s approval that describes,
at a minimum, how a stable borehole will be drilled with minimal rugosity (roughness of
the borehole wall), how complete removal of drilling fluid will be accomplished, how the
cement system design addresses challenges to zonal isolation, how other factors that
could interfere with the proper placement of the cement around the casing will be
addressed, and how the casing and cement will assure integrity throughout the life cycle
of the well.
c. Adherence to the drilling, casing and cementing plan, as well as integrity testing will be a
condition of the permit.
d. Unless the Department, upon demonstration by the applicant that its proposed drilling,
casing and cementing plan is adequately protective, the plan shall meet the following
criteria:
i. The conductor casing must be cemented to the surface.
ii. The surface casing must extend from the surface to at least 100 feet below the
lowest underground source of drinking water and be cemented along its entire
length.
iii. The intermediate casing must be installed and cemented from its greatest depth
to the bottom of the surface casing.
iv. Production casing must be cemented along the horizontal portion of the well
bore and to at least 500 feet above the highest formation where hydraulic
fracturing will be performed, or to the base of the intermediate casing,
whichever is shallower.
v. A representative sample of each cement formulation shall be tested before use
under conditions that are similar to those found in the well where the cement
will be used.
vi. Open hole logging must be performed and used to optimize the design and
installation of the well.
e. All casing installed in a well shall be steel alloy casing and have a minimum internal yield
pressure rating designed to withstand at least 1.2 times the maximum pressure to which
the casing may be subjected during drilling, production, or stimulation operations; .
103
f.
The minimum internal yield pressure rating shall be based upon engineering calculations
that shall be included in the plan;
g. Thread and coupling designs for casing and tubing must meet or exceed the maximum
anticipated tensile, compressive, burst and bending stress conditions for the well. Casing
strings with threads should be assembled to the correct torque specifications to ensure
leak-proof connections.
h. Operators must use a sufficient number of centralizers to properly center the casing in
each borehole. The cement shall be allowed to set at static balance or under pressure
for a minimum of 12 hours and must have reached a compressive strength of at least
500 psi before drilling the plug, or initiating any integrity testing
i. Reconditioned casing may be permanently set in a well only after it has passed a
hydrostatic pressure test with an applied pressure at least 1.2 times the maximum
internal pressure to which the casing may be subjected, based upon known or
anticipated subsurface pressure, or pressure that may be applied during stimulation,
whichever is greater, and assuming no external pressure. The casing shall be marked to
verify the test status. All hydrostatic pressure tests shall be conducted by a method
approved by the Department. The owner shall provide a copy of the test results to the
Department before the casing is installed in the well.
j. Before commencing hydraulic fracturing, the permittee must certify the sufficiency of
the zonal isolation to MDE with supporting data in the form of well logs, pressure test
results, and other appropriate data.
8. Integrity testing will be required.
a. An applicant for a drilling permit will be required to provide a plan for integrity and
pressure testing of the cased hole for approval by MDE. Segmented radial cement bond
logging (SRCBL) shall be used, supplemented by other methods such that the
Department may require in a permit, such as omnidirectional cement bond logging and
neutron logging.
b. If there is evidence of inadequate casing integrity or cement integrity, the Department
must be notified and remedial action proposed.
c. Integrity testing must be performed periodically during the lifetime of the well. The
specific types of tests and the frequency of testing will be addressed in each permit.
d. Integrity testing will be required when a well is re-fractured.
e. All integrity test results must be reported to MDE.
9. Top-down BAT must be implemented on all air pollution emission sources.
a. Green completion shall be achieved on all gas wells drilled in Maryland.
b. An applicant for a permit must prepare a Leak Detection and Repair Plan that follows
EPA’s Leak Detection and Repair: A Best Practices Guide.
http://www.epa.gov/compliance/resources/publications/assistance/ldarguide.pdf and
submit the plan to MDE for approval. An approved plan shall be incorporated into the
permit.
104
10.
11.
12.
13.
c. When evaluating top-down BAT, the applicant for the permit must include EPA’s Natural
Gas STAR Program’s Recommended Technologies and Practices, to the extent they apply
to the applicant’s operations.
Offsetting methane emissions
a. Permittees will be required to estimate the remaining methane emission (after
implementing top-down BAT) and report those emissions to MDE annually, converted
into CO2 equivalent emissions.
b. Where practicable, estimates should be verified by operational data from the
permittee’s leak detection and repair program.
c. The methane emissions must be offset. MDE will work with stakeholders to establish a
GHG offset program for methane, building from ongoing efforts of the Regional
Greenhouse Gas Initiative and other greenhouse gas offset initiatives across the
country. If such a system is established, MDE may also require permittees to offset
leakage at a ratio greater than 1:1.
Flaring shall be allowed only if the content of flammable gas is inadequate to sustain
combustion, or when flaring is required for safety. The following circumstances shall not justify
flaring:
a. Inadequate water disposal capacity
b. Undersized flowback equipment
c. Except for wells drilled pursuant to a bifurcated permit25 for exploration only, lack of a
pipeline connection
When flaring is permitted during well completion, re-completions or workovers26 of any well,
operators must adhere to the following requirements:
a. Operators must either use raised/elevated flares or an engineered combustion device
with a reliable continuous ignition source, which have at least a 98 percent destruction
efficiency of methane. No pit flaring is permitted.
b. Flaring may not be used for more than 30-days on any exploratory or extension wells
(for the life of the well), including initial or recompletion production tests, unless
operation requires an extension.
c. Flares shall be designed for and operated with no visible emissions, except for periods
not to exceed a total of five minutes during any two consecutive hours.
Engines
a. All on-road and non-road vehicles and equipment using diesel fuel must use Ultra-Low
Sulfur Diesel fuel (maximum sulfur content of 15 ppm).
b. All on-road vehicles and equipment must limit unnecessary idling to 5 minutes.
c. All trucks used to transport fresh water or flowback or produced water must meet EPA
Heavy Duty Engine Standards for 2004 to 2006 engine model years, which include a
25
A bifurcated permit can be issued under Md. Env. Code, § 14-106 when the drilling will be conducted in geologic formations not yet proven to
be productive. Because the Marcellus shale formation has been demonstrated to be productive, bifurcated permits shall not be issued for
drilling in the Marcellus shale in Maryland. Exploratory wells in the Marcellus shale will require a permit under Md. Env. Code, § 14-104.
26
Workovers include the repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the
production of hydrocarbons; the term includes refracturing.
105
14.
15.
16.
17.
18.
19.
combined NOx and NMHC (non-methane hydrocarbon) emission standard of 2.5 g/bhphr.
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.)
Noise shall be reduced to the lowest practicable level.
a. The Departments will require that applicants provide a power plan that results in the
lowest practicable impact from the choice of energy source, including consideration of
the impact of noise from on-site generators.
b. Noise reduction devices must be used on all equipment at the pad site.
c. Noise modeling must be done to demonstrate that noise levels will be met and noise
monitoring after operation begins must be done to confirm.
All drilling fluids and cuttings must be managed on the well pad in a closed loop system without
the use of a reserve pit for mud or cuttings.
Flowback and produced water shall be managed in a closed loop system of tanks or containers
at the pad site.
Wastes and wastewater must be handled in accordance with law and managed in a way that
prevents pollution of the environment.
a. Permittees will be required to keep a record of the volumes of wastes and wastewater
generated on-site, the amount treated or recycled on-site, a record of each shipment
off-site and a confirmation that the waste was received at the designated facility.
b. All trucks, tankers and dump trucks transporting liquid or solid wastes shall be fitted
with GPS tracking systems to help adjust transportation plans and identify responsible
parties in the case of accidents/spills.
c. Cuttings, drilling mud, flowback, produced water, residue from treatment of flowback
and produced water, and any equipment where scaling is likely to occur or sludge is
likely to collect must be tested for radioactivity and disposed of in accordance with law.
d. If cuttings show no level of radioactivity beyond background, and meet other criteria
established by MDE, including sulfates and salinity, MDE may permit on-site disposal of
cuttings.
Flowback and produced water shall be recycled to the maximum extent practicable. Unless the
applicant can demonstrate that it is not practicable, the permit shall require that not less than
90 percent of the flowback and produced water be recycled, and that the recycling be
performed on the pad site of generation.
Disclosure of chemicals
a. Applicants for permits to drill gas wells shall be required to provide MDE with the name,
CAS number and concentration of every chemical constituent of every commercial
chemical product brought to the site. Unless the applicant attests that the information is
a trade secret, this information shall be public information.
b. Following well completion, the operator must provide MDE with a list of all chemicals
used in fracturing, the weight of each used, and the concentration of the chemical in the
106
fracturing fluid. Unless the applicant attests that the information is a trade secret, this
information shall be public information.
c. If a claim is made that the concentration of a chemical in either a commercial chemical
product or the fracturing fluid is a trade secret, the operator must attest to that fact
and, in addition to the complete list, provide a second list that includes every chemical
by name and CAS number, but does not link the chemical to a specific commercial
product or reveal the concentration. This list shall be public information.
d. MDE may share trade secret information with other State and federal agencies that
agree to protect the confidentiality of the information.
e. The operator must provide the local emergency response agency with the list of
chemicals (or the second list, in the event trade secrecy is claimed) and provide a copy
of the Safety Data for every commercial product brought to the well site that contains
an OSHA hazardous chemical.
f. A health care professional who states, orally or in writing, that he or she needs the trade
secret information to diagnose or treat a patient, must be given that information
immediately and may use it only as medically necessary.
g. Upon written request and statement of need, certain public health care professionals
must be given the information, but the delivery may be conditioned on the execution of
a confidentiality agreement.
h. A person claiming trade secret must provide the supplier’s or service company’s contact
information, including the name of the company, an authorized representative, and a
telephone number answered 24/7 by a person with the ability and authority to provide
the trade secret information in accordance with the regulations.
20. Gathering lines shall be properly constructed and operated to prevent any leaks.
a. The owner and operator of any pipeline shall participate as an “owner-member” as that
term is defined in the Maryland Public Utilities Code, Section 12-101, in a one-call
system, which in Maryland is generally known as the “Miss Utility” program. Upon the
request of someone planning to excavate in the area, the locations of these pipelines
could be marked so that the digging could avoid them.
b. All pipelines and fittings appurtenant thereto used in the drilling, operating or producing
of oil and/or natural gas well(s) shall be designed for at least the greatest anticipated
operating pressure or the maximum regulated relief pressure in accordance with the
current recognized design practices of the industry.
21. The well must be protected against blowouts.
a. The well must be equipped with blowout prevention equipment with two or more
redundant mechanisms.
b. Blow out preventers must be tested at a pressure at least 1.2 times the highest pressure
expected to be experienced during the life of the well. If this highest pressure occurs
during well stimulation, it must be tested at a pressure at least 1.2 times higher than
that experienced during well stimulation.
c. The blow out preventer must be tested on a weekly basis.
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22. The operator must perform a tiltmeter or microseismic survey for the first well hydraulically
fractured on each pad to provide information on the extent, geometry and location of
fracturing. The permittee shall provide this information to MDE
23. Diesel fuel shall not be used in hydraulic fracturing.
24. A methane leak detection and repair plan that conforms to EPA’s Natural Gas STAR Program
guidelines and EPA’s best practice guidelines for leakage detection and repair programs must be
submitted to MDE for approval with the application for a well permit. It must address leak
detection and repair from wellhead to transmission line and assure prompt repair of leaks.
Records of leak detection and repair shall be made available to MDE upon request.
25. Night lighting may be used only when necessary, it must be directed downward, and low
pressure sodium light sources must be used wherever possible. If drill pads are located within
1,000 feet of aquatic habitat, screens or restrictions on the hours of operation may be required
to reduce light pollution further. 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.
26. The applicant must submit a plan with every well application for preventing the introduction of
invasive species (plants and animals) and controlling any invasive that is introduced. The
invasive species management plan should emphasize avoidance, early detection and rapid
response. Invasive species monitoring will be required at the appropriate times of the year to
identify early infestations. The plan must include, at a minimum:
a. flora and fauna inventory surveys of sites prior to operations, including water
withdrawal sites;
b. procedures for avoiding the transfer of species by clothing, boots, vehicles; and water
transfers including assuring that the water withdrawal equipment is free from invasive
species before use and before it is removed from the withdrawal site;
c. interim reclamation following construction and drilling to reduce opportunities for
invasion;
d. annual monitoring and treatment of new invasive species populations as long as the
well is active; and
e. post-activity restoration to pre-treatment community structure and composition using
seed that is certified free of noxious weeds.
27. Each applicant for a well permit must prepare and submit to MDE for approval a site-specific
emergency response plan for preventing the spills of oil and hazardous substances. The plan
should include, at a minimum:
a. using drip pans and secondary containment structures to contain spills,
b. conducting periodic inspections,
c. using signs and labels,
d. having appropriate personal protective equipment and appropriate spill response
equipment at the facility,
e. training employees and contractors, and
f. establishing a way of informing local water companies promptly in the event of spills or
releases,
108
g. consulting with the governing body of the local jurisdiction in which the well is located
to verify that local responders have appropriate equipment and training to respond to
an emergency at a well, and
h. establishing a communications plan.
28. The operator shall identify specially trained and equipped personnel who could respond to a
well blowout, fire, or other incident that personnel at the site cannot manage. These specially
trained and equipped personnel must be capable of arriving at the site within 24 hours of the
incident.
29. The operator shall secure the site. At a minimum, security shall include:
a. Perimeter fencing
b. Providing local emergency responders with duplicate keys to locks
c. Posting appropriate signage
30. The operator shall reclaim the site in two stages: interim reclamation following well completion
to stabilize the ground and reduce opportunities for invasive species and final restoration using
species native to the geographic range and seed that is certified free of noxious weeds.
Reclamation shall address all disturbed land, including the pad, access roads, ponds, pipelines
and locations of ancillary equipment. Pre-development and post-development photographic
documentation will be required to ensure site closure conditions are satisfied.
Monitoring, Recordkeeping and Reporting
1. State agencies will develop standard protocols for baseline and environmental assessment
monitoring, recordkeeping and reporting. In addition, the State agencies will develop standards
for monitoring during operations at the site, including drilling, hydraulic fracturing, and
production.
2. 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.
3. 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.
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