Recommended Best Management Practices 

for Marcellus Shale Gas Development in 

Maryland 

Keith N. Eshleman & Andrew Elmore (PIs) 

Appalachian Laboratory 

University of Maryland Center for Environmental Science 

Frostburg, MD 21532 

Final Report submitted to: 

Maryland Department of the Environment 

Baltimore, MD 

February 18, 2013
 

ii 

Acknowledgments 

We solicited and received the help of quite a few people during the completion of this project. 

While the project investigators (KNE and AJE) are responsible for the content of the final report, 

we especially acknowledge three individuals who helped us with the organization, content, and 

writing of several chapters: Russell R. Dickerson (Department of Atmospheric and Oceanic 

Science, University of Maryland; Chapter 2) Jeanne M. VanBriesen (Department of Civil and 

Environmental Engineering, Carnegie Mellon University; Chapter 4); and Todd R. Lookingbill 

(Department Geography and the Environment, University of Richmond; Chapter 5). Previous 

time commitments precluded them from assisting with other sections of the report, so they 

are listed as chapter co-authors. We thank the following individuals for providing us with 

data: Scott Bearer, Deborah Carpenter, Jennifer Chadwick-Moore, Kevin Coyne, Lynn 

Davidson, Gregory Day, Dan Feller, Dave Foreman, Mike Garner, John Grace, Jeff Halka, Kara 

Hawkins, Jaron Hawkins, Greg Hildreth, Zoe Johnson, Catherine McCall, Phung Pham, Gene 

Piotrowski, Matt Rowe, Matt Sell, Frank Siano, Matthew Stover, and Kevin Wagner. Robert 

Sabo compiled much of the extant literature on best practices that underpinned our analyses of best 

practices. Steven Guinn produced all of the maps used in this report and performed many of the 

geographic analyses on which our recommendations are based. Robert Hilderbrand contributed text 

and comments to Chapter 6. Finally, Christine Conn (Maryland DNR), Brigid Kenney (MDE), Ron 

Klauda (Maryland DNR) and several other anonymous reviewers provided constructive criticism of 

an earlier draft of the report. 

 
 

iii 

Table of Contents 

Cover page ............................................................................................................................................ i 

Acknowledgments ............................................................................................................................... ii 

Table of Contents ............................................................................................................................... iii 

List of Acronyms and Abbreviations ................................................................................................. vi 

Summary of key findings and major recommendations ....................................................................... 1 

Chapter 1. General, planning, and permitting BMPs ................................................................. 1-1 

A. Pre-development environmental assessment ......................................................................... 1-3 

B. On-site and off-site monitoring ............................................................................................. 1-5 

C. Comprehensive drilling plans (CDP) ................................................................................... 1-7 

D. Well pad spacing ................................................................................................................ 1-10 

E. Setback requirements .......................................................................................................... 1-11 

F. Identification of freshwater aquifers and groundwater flowpaths ...................................... 1-12 

G. Stakeholder engagement ..................................................................................................... 1-15 

H. Special siting criteria .......................................................................................................... 1-16 

I. Reclamation planning .......................................................................................................... 1-20 

J. Well permitting, county and state coordination, and financial assurance ............................ 1-21 

K. Key recommendations ........................................................................................................ 1-25 

L. Literature cited ..................................................................................................................... 1-27 

Chapter 2. Protecting air quality .................................................................................................. 2-1 

A. Reducing pollutant and pollutant precursor emissions from MSGD operations ................... 2-3 

B. On-site and off-site air quality monitoring ............................................................................ 2-6

C. Key recommendations ........................................................................................................... 2-6 

D. Literature cited ...................................................................................................................... 2-7 

Chapter 3. Well engineering and construction practices to ensure integrity and isolation .... 3-1 

A. Well planning ....................................................................................................................... 3-2 

B. Drilling .................................................................................................................................. 3-4 

C. Casing and cementing ........................................................................................................... 3-7 

D. Well logging ....................................................................................................................... 3-10 

E. Pressure testing .................................................................................................................... 3-12 

F. Blow-out prevention ............................................................................................................ 3-12 

G. Completing and hydraulic fracturing ................................................................................. 3-13 

H. Use of well development techniques other than hydraulic fracturing ................................ 3-14 

I. Determining the extent of induced fractures ........................................................................ 3-15 

J. Plugging ............................................................................................................................... 3-16 

K. Key recommendations ......................................................................................................... 3-18 

L. Literature cited ..................................................................................................................... 3-19 

Chapter 4. Protecting water resources ......................................................................................... 4-1 

A. Siting requirements: setbacks and restrictions ..................................................................... 4-3 

B. Monitoring of water resources prior to, during, and following development ....................... 4-6 

C. Water pollution, stormwater management, and erosion and sediment control .................... 4-8 

D. Water withdrawals ............................................................................................................... 4-15 

E. Comprehensive basin-scale water management planning. .................................................. 4-19 

F. Water storage and delivery .................................................................................................. 4-20 

G. Alternative water sourcing .................................................................................................. 4-21 

H. Chemical delivery, storage on-site, and transfers ................................................................ 4-22 
 

iv 

I. Identification of chemicals .................................................................................................... 4-23 

J. Drilling and drilling wastes .................................................................................................. 4-23 

K. On site management of produced waters and wastewaters ................................................. 4-24 

L. Management of produced water (including recordkeeping, manifesting) ........................... 4-25 

M. Treatment of produced water .............................................................................................. 4-27 

N. Disposal of produced water or residual treatment wastes ................................................... 4-29 

O. Reclamation and closure (decommissioning) ...................................................................... 4-30 

P. Naturally occurring radioactive materials (NORM) ............................................................ 4-31 

Q. Key recommendations ......................................................................................................... 4-32 

R. Literature cited ..................................................................................................................... 4-33 

Chapter 5. Protecting terrestrial habitat and wildlife ................................................................ 5-1 

A. Well pad spacing and siting ................................................................................................... 5-1 

B. Impoundments ....................................................................................................................... 5-4 

C. Riparian setbacks ................................................................................................................... 5-6 

D. Special protection areas ......................................................................................................... 5-7 

E. Noise and light ..................................................................................................................... 5-10 

F. Construction of roads and pipelines ..................................................................................... 5-12 

G. Invasive plants and wildlife ................................................................................................. 5-13 

H. Reclamation ......................................................................................................................... 5-14 

I. Key recommendations .......................................................................................................... 5-15 

I. Literature cited ...................................................................................................................... 5-16 

Appendix 5A ............................................................................................................................ 5-19 

Chapter 6. Protecting aquatic habitat, wildlife, and biodiversity ............................................. 6-1 

A. Buffers and setbacks .............................................................................................................. 6-3 

B. Special protection of high-value assets ................................................................................ 6-5 

C. Design and construction of well pads, access roads, pits, utility corridors, and pipelines ... 6-9 

D. Erosion and sediment controls ............................................................................................ 6-12 

E. Invasive species controls .................................................................................................... 6-13 

F. Key recommendations .......................................................................................................... 6-13 

G. Literature cited .................................................................................................................... 6-14 

Chapter 7. Protecting public safety .............................................................................................. 7-1 

A. Spill prevention and emergency response ............................................................................. 7-1 

B. Site security ........................................................................................................................... 7-3 

C. Transportation planning ......................................................................................................... 7-4 

D. Key recommendations ........................................................................................................... 7-5 

E. Literature cited ....................................................................................................................... 7-6 

Chapter 8. Protecting cultural, historical, and recreational resources ..................................... 8-1 

A. Identification of sites ............................................................................................................. 8-1 

B. Setback requirements and mitigation .................................................................................... 8-2

C. Key recommendations ........................................................................................................... 8-5 

D. Literature cited ...................................................................................................................... 8-6 

Chapter 9. Protecting quality of life and aesthetic values ......................................................... 9-1 

A. Hours of operation ................................................................................................................ 9-1 

B. Noise control ......................................................................................................................... 9-2 

C. Road impacts and transportation planning ........................................................................... 9-2 

D. Visual pollution/viewsheds .................................................................................................. 9-4 

E. Key recommendations ........................................................................................................... 9-5 

F. Literature cited ....................................................................................................................... 9-6 
 

v 

Chapter 10. Protecting agriculture and grazing ....................................................................... 10-1 

A. Protection of prime farmland .............................................................................................. 10-2 

B. Key recommendations ......................................................................................................... 10-4 

C. Literature cited ..................................................................................................................... 10-4 

 
vi 

List of Acronyms and Abbreviations 

AMD acid mine drainage 

API American Petroleum Institute 

BCF billion cubic feet 

bhp-hr brake horsepower-hour 

BioNET Biodiversity Conservation Network 

BMP best management practice 

BOPE blow-out prevention equipment 

BTEX benzene, toluene, ethylbenzene, and xylene 

CBL cement bond logging 

CBM coal bed methane 

CDP comprehensive drilling plan 

CNHI County Natural Heritage Inventory 

CO carbon monoxide 

CO2 carbon dioxide 

COD chemical oxygen demand 

COGCC Colorado Oil and Gas Conservation Commission 

COMAR Code of Maryland Regulations 

CWA Clean Water Act 

DMRM Division of Mineral Resources Management (OH) 

DNR Department of Natural Resources (MD) 

EAF environmental assessment form 
vii 

ELAP Environmental Laboratory Accreditation Program 

ERP emergency response plan 

ERT Environmental Review Tool 

ESC erosion and sediment control 

FCA Forest Conservation Act (MD) 

FEMA Federal Emergency Management Agency 

ft feet 

GHG greenhouse gas 

HAB harmful algal blooms 

HAP hazardous air pollutant 

HC hydrocarbon 

HDPE high density polyethylene 

HDT Hoffman Drainage Tunnel 

HF hydraulic fracturing 

HP horsepower 

HVHF high volume hydraulic fracturing 

HQW high quality waters 

HUC hydrologic unit code 

ICPRB Interstate Commission on the Potomac River Basin 

IR infrared radiation 

kg kilogram 

km kilometers 

km2

 square kilometers 
viii 

LLRW low-level radioactive waste 

LPG liquefied petroleum gas 

L/s liters per second 

LWD logging while drilling 

MALPF Maryland Agricultural Land Preservation Foundation 

MBSS Maryland Biological Stream Survey 

MDA Maryland Department of Agriculture 

MDE Maryland Department of the Environment 

MG million gallons 

MGD million gallons per day 

mg/L milligrams per liter 

MGS Maryland Geological Survey 

MHT Maryland Historical Trust 

MMCF million cubic feet 

MSDS material safety data sheet 

MSGD Marcellus shale gas development 

MSSCS Maryland Synoptic Stream Chemistry Survey 

MWD measurement while drilling 

NAAQS National Ambient Air Quality Standard 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NORM naturally occurring radioactive materials 

NOx nitrous oxide 

NPDES National Pollutant Discharge Elimination System 
ix 

NRC National Research Council 

NSPS New Source Performance Standards 

NWI National Wetlands Inventory 

NYSDEC New York State Department of Environmental Conservation 

O3 ozone (photochemical smog) 

ONRW outstanding national resource waters 

OVM organic vapor meter 

ORSANCO Ohio River Valley Water Sanitation Commission 

PA DCNR Pennsylvania Department of Conservation and Natural Resources 

PA DEP Pennsylvania Department of Environmental Protection 

pCi/g picocuries per gram 

PE professional engineer 

PM2.5 fine particulate matter (< 2.5 μm) 

PNDI Pennsylvania natural diversity inventory 

PNHP Pennsylvania Natural Heritage Program 

POTW publically owned treatment works 

PPC prevention, preparedness, and contingency 

psi pounds per square inch 

QA/QC quality assurance/quality control 

RAIN River Alert Information Network 

RCRA Resource Conservation and Recovery Act 

RGGI Regional Greenhouse Gas Initiative 

RP recommended practice 
x 

RW radioactive waste 

SAV submerged aquatic vegetation 

SHA State Highway Administration (MD) 

SRBC Susquehanna River Basin Commission 

SRCBL segmented radial cement bond logging 

STRONGER State Review of Oil and Natural Gas Environmental Regulations, Inc. 

SWPPP stormwater pollution prevention program 

TCEQ Texas Commission on Environmental Quality 

TCF trillion cubic feet 

TDS total dissolved solids 

TENORM technologically-enhanced, naturally-occurring radioactive materials 

TNC The Nature Conservancy 

TSS total suspended solids 

TVD true vertical depth 

UIC Underground Injection Control 

ULSD ultra low sulfur diesel 

USACE United States Army Corps of Engineers 

USDA United States Department of Agriculture 

USDW underground source of drinking water 

USEPA United States Environmental Protection Agency 

USFWS United States Fish and Wildlife Service 

USGS United States Geological Survey 

VDL variable density log 
xi 

VOC volatile organic compound 

WOC wait on cement 

WQS water quality standards 

WSSC Wetlands of Special State Concern 

WVDEP West Virginia Department of Environmental Protection 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

i 

Summary of key findings and major recommendations1

The Marcellus shale formation underlying numerous Appalachian states is considered the largest 

gas-bearing shale formation in the United States. The thousands of new gas wells that have been 

drilled in this region since 2004 are testimony to a revolution in domestic natural gas production 

in the U.S. through so-called “unconventional” development that includes both modern 

horizontal drilling and high volume hydraulic fracturing technologies. Unlike neighboring 

Pennsylvania that participated fully in the initial boom in exploration and production between 

2005 and 2009 (drilling has occurred extensively both on private and public lands in 

Pennsylvania), Maryland (with a significantly smaller resource) has chosen to stay on the 

sidelines with an unofficial moratorium on unconventional Marcellus shale gas development 

(MSGD) while it studies the lessons from other states, determines whether development can go 

forward safely, and evaluates it options. The present study of best management practices (BMPs) 

for Marcellus shale gas development represents an effort to determine what actual practices 

would provide the maximum protection of Maryland’s environment, natural resources, and 

public safety should the state decide to move forward with development of this resource in the 

near future. 

We carefully reviewed the current regulations governing unconventional shale gas development 

in five other states (Colorado, New York, Ohio, Pennsylvania, and West Virginia), as well as the 

recommendations of many other expert panels and organizations that have reviewed both 

regulations and BMPs in these and other states. We visited several well pads as part of three 

organized field trips that allowed us to gain an important visual perspective of the operations, 

practices, and challenges involved in conducting MSGD. Wherever possible, we also reviewed 

the scientific literature to evaluate the proven effectiveness of different practices, but the lack of 

comprehensive, data-driven studies of the impacts of MSGD both on-site and off-site present a 

significant impediment to recommending best practices on the basis of this criterion alone. For 

this reason, we have explicitly chosen to identify and recommend specific BMPs that—mostly 

on the basis of our professional judgment—would provide as much protection of Maryland’s 

natural, cultural, historical and recreational resources; the environment; and public safety as can 

reasonably be provided while allowing MSGD to move forward. 

We believe that it is inevitable that there will be negative impacts from MSGD in western 

Maryland (and perhaps beyond the state’s borders) and that a significant portion of these “costs” 

will be borne by local communities. Heavy truck traffic on local roads, noise and odors 

emanating from drilling sites, conflicts with outdoor recreation, diminished tourism, reduced 

biodiversity, and deterioration of air and water quality are some examples of the types of impacts 

that are likely even under the best of circumstances. While difficult to quantify in economic 

terms, these “costs” will ideally be greatly outweighed by the benefits of increased economic 

activity—otherwise it is very difficult to make a case that MSGD should occur at all. Our goal 

was to identify and recommend specific BMPs that would provide maximum protection of 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. and Andrew J. Elmore, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532) 
K.N. Eshleman & A.J. Elmore (2013) Summary of key findings and major recommendations

ii 

Maryland’s environment, natural resources, and public safety. There are a variety of types of 

resources and hazards—in some cases overlapping—distributed across the western Maryland 

landscape that present important constraints on MSGD. For this reason, implementation of some 

BMPs will effectively result in the exclusion of MSGD from select areas of the region to reduce 

the risk of impacts, thus limiting to some degree the total volume of gas eventually extracted. 

Due to the nature of this activity in which well bores can be drilled horizontally 8,000 ft from the 

well pad, it will often be possible to drill under the most valuable and at-risk resources of 

western Maryland. This potential is enhanced through the use of multi-well pads that are capable 

of draining between one and two square miles of the target formation. Further, locating multiwell pads in dense clusters—with clusters spaced as far apart as is technically feasible—makes 

maximum use of horizontal drilling technology and could be an important BMP in terms of 

minimizing surface development impacts. With careful and thoughtful planning (e.g., co-location 

of associated infrastructure wherever possible), it may be possible to develop much of the gas 

resource in a way that converts less than 1-2% of the land surface, even when accounting for the 

need for ancillary infrastructure such as access roads, pipelines, and compressor facilities. While 

this build-out scenario would occupy much less surface area than other forms of development, 

even with the most protective BMPs in place it would certainly not be expected to occur without 

some significant negative impacts on the western Maryland region. 

Maryland already has a reasonably well-developed set of regulations that pertains mostly to 

conventional oil and gas development, but the state lacks a regulatory/enforcement structure to 

address unconventional gas development. Clearly, a regulatory program would have to quickly 

“ramp up” to effectively address the myriad issues that would be presented by MSGD in the state 

and to avoid some of the problems that have occurred elsewhere. An important best management 

practice is therefore to “go slow” and allow a new regulatory structure and experience in 

inspection and enforcement to evolve over time and effectively “catch up” to the new technology 

as MSGD proceeds. If and when MSGD moves forward in western Maryland, we believe that 

effective planning by local and state governments that moderates the rate at which the gas 

resource is developed across the region would help mitigate some of the negative effects of 

“boom-bust” cycles that have occurred elsewhere. There are a number of specific 

recommendations throughout this report that provide guidance in this area. 

In particular, perhaps the single most important among these recommendations is that the state 

should develop regulations to support the design and implementation of comprehensive drilling 

plans (CDPs) for MSGD. We envision a voluntary program similar to Colorado’s approach (and 

the program that has been used to develop the Marcellus gas resource in Pennsylvania state 

forests), but one that provides strong incentives for operators willing to consider this option. 

After identifying foreseeable oil and gas activities in a defined geographic area upfront, energy 

companies would work cooperatively with other stakeholders (including state natural resource 

agencies, counties, citizen groups, etc.) to develop an integrated plan for efficiently exploiting 

the resource while minimizing impacts on communities, ecosystems, and natural resources. The 

CDP approach offers many advantages, but the most important one is that it provides a way of 

effectively channeling this industrial activity into those areas where fewer of the most sensitive 

resources are “in harm’s way” and where new infrastructure needs (e.g., roads, pipelines) are 

lower. Logically, the first approved CDP would most likely result in permitting an area for 

drilling where major drilling hazards, risks to public safety, and impacts on sensitive ecological, 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

iii 

recreational, historical and cultural resources can be largely avoided. Since we expect that the 

planning process for a CDP would be longer than for individual well drilling permits, another 

major advantage of this approach is that it could enable MSGD to move forward at a somewhat 

slower, more manageable rate. One way the state might incentivize comprehensive gas 

development planning could be by reducing permit fees and bonding requirements for wells 

covered under a CDP. Over time, monitoring data collected both on-site and off-site to document 

impacts (or non-impacts) would be used by the industry to improve BMPs (this is the way the 

BMP process is supposed to work). Additional CDPs would presumably be dependent upon the 

industry demonstrating that any impacts from earlier drilling were within acceptable limits or 

that newer practices were significantly better at reducing any unacceptable impacts observed in 

prior phases. 

A critically important consideration influencing the success of CDPs in Maryland would be 

careful site selection based on pre-development environmental assessment for well pads and 

related infrastructure. A careful pre-drilling environmental assessment would include, at a 

minimum, an assessment of all existing data combined with two years of pre-drilling monitoring, 

including surface and groundwater testing, inventories of rare, threatened and endangered 

species, and an assessment of the potential to introduce invasive species during site development 

or water procurement. Should any changes in observed water quality occur during drilling or 

production, pre-drilling assessment should make possible a defendable determination of liability. 

It is important to remember that western Maryland is a geographically small, rural, and 

mountainous landscape, offering residents a high quality of life, in part due to abundant 

biological, recreational, and cultural resources with exceptional value. Because of its 

mountainous landscape and history of coal mining, there are also many hazards in western 

Maryland that must be avoided in the interest of long-term well integrity and public safety. The 

goal of best management practices for siting MSGD-related infrastructure would be to provide a 

safe environment for all residents, avoid conflicts with existing land uses, and observe all ongoing efforts to conserve biological diversity. Throughout this report we have recommended 

specific setbacks from irreplaceable natural areas, aquatic habitat, and hotspots for biodiversity 

(e.g., caves). Maryland has recently placed an emphasis on mapping valuable resources; this 

activity should continue and the resulting data should be made available to prospective drilling 

operators to optimize the placement of well pads and related infrastructure. 

One BMP we have highlighted throughout this report is the avoidance of underground voids, 

which can often be justified based on caves’ conservation value for many rare threatened and 

endangered species. Additionally, complications from encountering a cave (or deep coal mine) 

during drilling can jeopardize the integrity of the well, leading to an increased chance of leaks, 

methane contamination of underground sources of drinking water, and even blowouts. Although 

it is standard practice in many states to drill down through subterranean voids, our research 

suggests that this practice comes with important risks and at least one state has begun looking at 

the technique with greater scrutiny. A best practice for Maryland would be to avoid all 

underground voids by employing the best mapping and detection technologies and then applying 

additional setbacks when siting the borehole. Similarly, there are several clusters of historic 

conventional gas wells throughout western Maryland. Because these boreholes provide a 

potential conduit for gas and possibly brines to migrate upwards into underground sources of 

drinking water, we recommend that all portions of new unconventional gas wells (vertical and 
K.N. Eshleman & A.J. Elmore (2013) Summary of key findings and major recommendations

iv 

horizontal) be positioned at least 1⁄4 mile from such boreholes. Finally, at least until it can be 

shown that hydraulic fracturing can be done safely within relatively close proximity to 

underground sources of drinking water, we recommend that Maryland prudently follow guidance 

from New York’s experience in regulating unconventional shale gas development and not permit 

MSGD (or any other unconventional gas development) where the Marcellus formation is located 

within 2,000 vertical ft of the ground surface. 

Despite best management practices designed to keep MSGD infrastructure away from our most 

treasured assets, there will always be impacts, which left unmitigated would adversely affect 

tourism, public safety, and the quality of life for residents and visitors alike. We, therefore, 

recommend implementing a suite of state-of-the-art mitigative techniques that would aim to limit 

the impact of MSGD should Maryland decide to invest fully in this new industry. The first of 

these techniques would seek to limit total impervious surface (e.g., pavement, buildings, gravel 

roads, well pads) to 2% for any watershed currently below this threshold. There is abundant 

scientific evidence that watershed impervious surface area is a robust indicator of cumulative 

impacts to watershed structure and functioning. Secondly, we recommend imposing a “no-netloss-of-forest” requirement on MSGD. This would tend to push well pad development into nonforest areas, but also require mitigation plantings of trees whenever forests are cut to make way 

for MSGD infrastructure. There are many other important mitigative techniques that could be 

employed to reduce the overall impact of MSGD on biological, recreational, and cultural 

resources, and that ultimately help to maintain a high quality of life in western Maryland. These 

include the use of line power instead of diesel generators to protect air quality, sound barriers 

and visual screens to reduce the impacts of drill rigs and compressor stations, limits on hours of 

drilling operations to avoid peak tourism periods (e.g., hunting season for white tail deer), and 

thoughtful truck traffic regulation to reduce the impact of water hauling convoys on quiet rural 

roads. Finally, although many landowners might earn substantial profits from MSGD on their 

land, their neighbors who opt out should be protected from the worst impacts. Sensible zoning 

ordinances and reasonable property line setbacks are certainly one way to reduce conflicts, but 

we also recommend enhanced transparency and increased public advertising of planned drilling; 

no one should be surprised and concerns of all parties should be addressed fully before drilling 

begins. 

Our review of well engineering practices revealed that the gas development industry has 

responded to pressure to reduce its environmental footprint by developing a suite of best 

management practices to maintain the integrity of each well system, isolate the well from the 

surrounding subsurface environment, and effectively contain the produced gas and other fluids 

within the well’s innermost production conduit; in so doing, the gas can ultimately be transported 

through ancillary pipelines for processing and delivery to market, while the wastewater (i.e., 

“flowback”, brines) that is returned to the surface can be efficiently captured, contained, treated, 

and ultimately recycled (while things are rapidly changing, the industry still relies very heavily 

on underground injection as the ultimate disposal process). The American Petroleum Institute 

(API)—as the technical arm of the oil and gas industry—has taken the lead in reviewing and 

evaluating the industry’s practices for drilling, completing, and operating oil and natural gas 

wells; on the basis of its on-going technical reviews of various practices, API has published an 

extensive number of documents describing so-called “recommended practices” (RPs) which it 

communicates and shares with the industry. Many of these RP’s explicitly address problems in 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

v 

maintaining well integrity and provide standards that have been expressly adopted by state 

regulatory authorities. If Maryland decides to begin permitting MSGD, we recommend that any 

operator who proposes drilling in the state should be required—at a minimum—to adopt API’s 

RPs and standards for well planning, well design, well construction, well completion, and well 

decommissioning. These practices can certainly be improved upon (for example, through more 

widespread field testing), and we believe it is very likely that API will gradually refine its RPs 

pertaining specifically to unconventional shale gas development. Maryland should require all 

operators to employ drilling, completion, and environmental control technologies and practices 

that fully meet these evolving standards and that are considered up-to-date. 

The current BMP for handling drilling fluids, hydraulic fracturing chemicals, wastewaters, and 

solid wastes on-site is through the use of a “closed-loop drilling system” in which all fluids are 

kept stored in watertight tanks that sit within secondary containment on lined and bermed “zerodischarge” well pads that can provide tertiary containment of contaminants and 100% retention 

of stormwater. All transfers of materials must be performed carefully on the pad so that any 

spills that occur can be quickly and fully contained. This type of drilling system—if properly 

designed and operated—would be expected to provide the lowest risk of contaminant leakage 

off-site such as might occur during extreme weather events. Under no circumstances should open 

pits for storage of wastes or wastewaters be allowed in Maryland. Maryland will need to 

carefully review its stormwater regulations as they pertain to oil and gas extraction and find a 

way to treat these industrial sites in the same way that other “hotspots” are treated. Operators 

will need to employ both “active” and “passive” stormwater management to effectively collect 

all water on a pad site over the entire life of drilling, completing, and producing operations to 

minimize soil erosion and downstream sedimentation (and avoid any inadvertent contaminant 

releases to the environment), although we explicitly recommend against employing any BMPs 

on-site that rely on soil infiltration due to the risks of groundwater contamination. 

Marcellus shale gas development produces large volumes of wastewater (flowback and produced 

water, commonly considered brines) that must be effectively contained, treated, and either safely 

disposed of or reused. First of all, under no circumstances should Maryland allow discharge of 

any untreated or partially-treated brine, or residuals from brine treatment facilities, into the 

waters of the state. To protect its water supplies, Maryland should establish a goal of 100% 

recycling of wastewater in permitting any MSGD within the state and have a very strong 

preference for on-site recycling of wastewater. Development of brine treatment plants that 

recycle water to drillers should be discouraged in favor of on-site treatment by mobile units and 

immediate reuse for hydraulic fracturing at the same site (or at a nearby site). On-site water 

treatment and reuse would be expected to minimize overall freshwater use for MSGD and reduce 

the volume of waste, while dramatically decreasing truck transport and associated impacts across 

the region. Along these lines, the state should also explore the use of non-potable water sources 

(e.g., acid mine drainage that represents a legacy of past coal mining practices in the region) as a 

way of supplementing needed water withdrawals from the region’s rivers and reservoirs. Finally, 

before permitting any development in the state, Maryland should carefully review the relevant 

regulations surrounding development and use of underground injection wells for produced water 

from MSGD, and at the same time evaluate the capacity of nearby states to accept produced 

water or residual concentrated brine from treatment of produced water. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-1 

1. General, planning, and permitting BMPs1

The Marcellus shale formation underlying numerous Appalachian states is considered the largest 

gas-bearing shale formation in the United States. The thousands of new gas wells that have been 

drilled in this region since 2004 are testimony to a revolution in domestic natural gas production 

in the US through so-called “unconventional” development that includes both modern horizontal 

drilling and high volume hydraulic fracturing technologies (Soeder and Kappel 2009). Unlike 

neighboring Pennsylvania that participated fully in the initial boom in exploration and production 

between 2005 and 2009 (drilling has occurred extensively both on private and public lands in 

Pennsylvania), Maryland (with a significantly smaller resource) chose to stay on the sidelines 

with an unofficial moratorium on unconventional Marcellus shale gas development (MSGD) 

while it studies the lessons from other states, determines whether development can go forward 

safely, and evaluates it options2. The present study of best management practices (BMPs) for 

Marcellus shale gas development represents an effort to determine what actual practices would 

provide the maximum protection of Maryland’s environment, natural resources, and public 

safety should the state decide to move forward with development of this resource in the near 

future. 

Only about 1.1% of the Marcellus shale gas play is in Maryland—by far the smallest portion of 

the 95,000 square miles of land underlain by this Devonian sedimentary formation that was 

deposited about 380 million years before present (USEIA 2012). We found many estimates of 

the gas resource contained in the Marcellus formation: (1) in 2002, the U.S. Geological Survey 

(USGS) estimated that the formation contained 1.9 trillion cubic feet (TCF); in 2008, Englander 

provided an estimate of 500 TCF; and in 2012, the U.S. Energy Information Administration 

(USEIA) estimated that 141 TCF remained that were technically recoverable as of January 1, 

20093

. Obviously, no one knows exactly how much gas exists within the Marcellus Shale 

underlying western Maryland, nor the value of the gas given uncertainties about future supplies 

and demands that would in part determine pricing. It has been estimated, however, that there is a 

50% chance that there is at least 1,286 billion cubic feet (BCF) present in Maryland (a “mid-case 

scenario”) and development of this resource could support aggregate production of 710 BCF 

from 365 wells on private land over a 30-year period from 2016 to 2045—valued in total at more 

than $4B (in constant 2011 US dollars; Sage Policy Group, Inc. 2012). Regardless of whether 

these estimates are at all realistic, it is obvious from Pennsylvania’s experience that very real 

economic benefits have been realized from MSGD (including generation of $413M in lease sales 

on 139,000 acres of state forest from 2008-2010, plus $88M in royalties from gas production of 

about 250 wells)4

. 

As part of our research, we have carefully reviewed the current regulations governing MSGD in 

five other states (Colorado, New York, Ohio, Pennsylvania, and West Virginia), as well as the 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. and Andrew J. Elmore, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532) 2

 Governor Martin O’Malley issued an Executive Order on June 6, 2011 establishing the Marcellus Shale Safe 

Drilling Initiative and Advisory Commission. 3

 Statistics are: MD (1.09%), NY (20.06%), OH (18.19%), PA (35.35%), VA (3.85%), WV (21.33%); USEIA 2012 

4

 Ellen Shutzbarger (PADCNR), personal communication (August 17, 2012) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-2 

recommendations of many other expert panels and organizations that have reviewed both 

regulations and BMPs in these and other states. Where possible, we also reviewed the scientific 

literature to determine the proven effectiveness of different BMPs, particularly those that are 

used in road construction and the protection of terrestrial and aquatic habitat and biodiversity. 

Finally, we visited several well pads as part of some organized field trips that allowed us to gain 

an important visual perspective of the operations, practices, and challenges involved in 

conducting MSGD. 

It is obvious that MSGD—if and when it comes to western Maryland—will be associated with 

both benefits and costs. Christopherson and Rightor (2011) describe recent MSGD in 

Pennsylvania and elsewhere as a classic “boom-bust cycle” that is characteristic of other 

extractive industries. The most evident impacts of the “boom” phase of the cycle are a very 

sudden and rapid increase in local economic activity due to drilling companies, crews, and gasrelated businesses moving into an area to extract the gas resource. During the “boom” period, 

there may be some local population growth, as well as increased hiring by the construction, retail 

and services sectors. Local business income, tax revenues, and royalty payments to owners of 

mineral rights also increase dramatically during the “boom” phase of the cycle; costs to 

communities can rise significantly at this time, for everything from road maintenance to public 

safety to schools. When drilling declines or ceases entirely as the commercially recoverable 

resource is depleted, the cycle enters the “bust” phase in which population and jobs may quickly 

depart the area—leaving fewer people to support the boomtown infrastructure. Communities 

where drilling-related benefits have effectively ended continue to be affected by a legacy of 

regional industrialization (e.g., truck traffic, gas storage facilities, compressor plants, and 

pipelines) and the impacts that are attendant thereto. Effective planning by local and state 

government that moderates the rate of MSGD in a region may mitigate the negative effects of the 

boom-bust cycle to a considerable degree (Christopherson and Rightor 2011). 

It is inevitable that there will be environmental impacts from MSGD in western Maryland 

throughout the “boom-bust” cycle (and perhaps beyond) and that a significant portion of these 

“costs” will be borne by local communities. Heavy truck traffic on local roads, noise and odors 

emanating from drilling sites, conflicts with outdoor recreation, diminished tourism, reduced 

biodiversity, and deterioration of air and water quality are some examples of the types of impacts 

that are likely even under the best of circumstances. While difficult to quantify in economic 

terms, these “costs” will ideally be greatly outweighed by the benefits of increased economic 

activity from the “boom-bust” cycle—otherwise it is very difficult to make a case that MSGD 

should occur at all. These impacts (“externalities”, in economic terms) must be expected even if 

best practices are implemented, local ordinances and state gas development regulations are 

carefully revised, and high standards of enforcement and inspection are put in place. Since these 

impacts are difficult to quantify in economic terms, we have explicitly chosen to identify and 

recommend specific BMPs that—largely on the basis of our professional judgment—would 

provide as much protection of Maryland’s natural, cultural, historical and recreational resources; 

the environment; and public safety as can reasonably be provided while allowing MSGD to 

move forward. The hope is that through implementation of these BMPs many of the most 

egregious environmental impacts can be prevented s (i.e., allowing the external costs to 

effectively be “internalized”). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-3 

We have also concluded from our review and from a simple geographic observation that 

Maryland is definitely not in control of its own environmental destiny when it comes to 

Marcellus shale gas development. The fact of the matter is that air and water pollutants (and 

even highway vehicles and U.S. dollars) are not observant of state boundaries. Since western 

Maryland (just two counties: Garrett and Allegany) is a relatively small “panhandle” sandwiched 

between Pennsylvania and West Virginia, in essence it cannot be truly isolated from activities in 

these and other states (e.g., some surface waters that originate in other states flow through 

Maryland; emissions of air pollutants from other states impact Maryland air quality; traffic, the 

human environment, and the economics of small towns in western Maryland are not immune 

from what is occurring in neighboring states). This also means that even if Maryland were to 

decide not to permit MSGD, there will no doubt be impacts felt in Maryland (both positive and 

negative) attributable to development of the resource in neighboring states that would mostly be 

beyond Maryland’s ability to control. 

Finally, we should note that the federal government has not played a major role in regulating 

unconventional gas development in Appalachia or elsewhere. There are several examples where 

federal statutes explicitly exempt unconventional gas development from federal environmental 

regulation. In particular, we note that oil and gas wastes are exempt from hazardous waste 

provisions of the Resource Conservation and Recovery Act (RCRA)—based on a determination 

by the U.S. Environmental Protection Agency (USEPA) that existing federal and state 

regulations were adequate to manage these wastes and apply RCRA Subtitle C regulation to 

these wastes would impose excessive costs on the energy industry (Hammer et al. 2012). 

Therefore, natural gas operators along with companies hauling or receiving these wastes are 

doing so without any requirement to meet the “cradle to grave” safeguards established under 

RCRA. An amendment to the Safe Drinking Water Act of 2005 excluded hydraulic fracturing 

activities under the definition of “underground injection” (with an exception made for fracturing 

fluid containing diesel fuel). Oil and gas operations are also exempt from NPDES stormwater 

permitting requirements under the Clean Water Act (Hammer et al. 2012). USEPA recently 

developed a federal rule mandating a BMP known as “green completion” as a way of capturing 

methane gas and reducing emissions of volatile organic compounds (VOCs) during the 

completion process—a practice that has been effectively used in Colorado and Fort Worth, Texas 

for several years. 

Implementation of BMPs for Marcellus shale gas development in Maryland must begin well in 

advance of actual exploration, site development, and drilling to properly address a variety of 

issues related to environmental assessment, planning, permitting, and bonding. For purposes of 

this report, we have explicitly defined the term ‘BMP’ in the most general way here to include 

virtually all aspects of shale gas development (USDOE 2011). Also, while we have focused our 

report on Marcellus shale gas development, our recommendations are likely applicable to 

unconventional development of other shale formations such as the Utica as well. In this chapter, 

we make specific recommendations of some critical actions that must be taken if MSGD is going 

to go forward in Maryland in as safe a way as possible. 

A. Pre-development environmental assessment 

Pre-development environmental assessment for MSGD should be used to identify (1) specific 

environmental conditions or features that would be expected to affect development of a 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-4 

particular site or region and (2) the environmental resources that are likely at risk from any future 

development activities. The ultimate goal of the assessment is to prevent conducting 

development activities that would cause temporary or lasting environmental damage from 

MSGD. It has been proposed both in New York (NYSDEC 2011) and Pennsylvania (Marcellus 

Shale Advisory Commission 2011) that state regulators of MSGD develop an environmental 

assessment form or “checklist” as part of the permit application process that would be used to: 

(1) identify the environmental resources (e.g., areas with high ecological value, exceptional value 

waters, etc.) or features that would be relevant to developing a particular site; (2) identify the 

appropriate setbacks or restrictions that would control development of a particular site; and (3) 

determine the environmental assessment activities or baseline monitoring that would be 

necessary for development to go forward. In Ohio, the Department of Mineral Resources 

Management (DMRM) conducts a site review prior to issuing a permit to evaluate any sitespecific conditions that might be attached to a permit to drill in an urban area (Ohio Legislative 

Service Commission 2010); Colorado Oil and Gas Conservation Commission (COGCC) 

maintains a website with maps of “Sensitive Wildlife Habitat” and “Restricted Surface 

Occupancy” areas that operators can use to determine whether a proposed oil or gas drilling site 

falls within such an area5

. Maryland regulations governing oil and gas development require a 

reasonably extensive environmental assessment6

, although it doesn’t appear to require any 

baseline monitoring activities as part of the process. 

Pre-development activities are essential to ensuring that MSGD in Maryland is conducted as 

safely as possible; some of these activities can, at least in part, be based on digital maps of the 

most sensitive ecological resources and those habitats in greatest need of protection (see 

Chapters 5 and 6). These maps are a product of the state’s long-term investments in 

environmental monitoring and resource assessment [e.g., Maryland Synoptic Stream Chemistry 

Survey (MSSCS); Maryland Biological Stream Survey (MBSS); etc.] and should be used as such 

by making them available to the public and to the industry at a dedicated website. Once these 

data layers are made available, a prospective shale gas developer—prior to submitting a drilling 

application or comprehensive drilling plan for review and approval—should be required to 

consult maps of (1) irreplaceable natural areas, (2) Maryland stronghold watersheds, (3) 

Maryland brook trout streams, (4) Tier II streams and drainages, (5) the entire stream network, 

and (6) other priority conservation areas to determine whether a proposed shale gas development 

would fall within an area that contains any “high-value assets”. Such an exercise would further 

allow a prospective operator to quickly determine the applicable setbacks and other BMPs 

governing MSGD at a proposed site—thus saving considerable time and money during the 

planning stages of a particular project. 

Given the relatively high density of sensitive ecological, recreational, historical, and cultural 

resources in western Maryland and a legacy of underground coal mining in the region, predevelopment environmental assessment should be conducted on a site-specific basis and include: 

(1) identification of all on-site drilling hazards such as underground mine workings (both active 

 

5

 COGCC Rule 1201, Identification of wildlife species and habitats 

6

 COMAR 26.19.01.06.C(3); see also 

www.mde.state.md.us/programs/Land/SolidWaste/ApplicationsFormsandInstructions/Documents/www.mde.state.

md.us/assets/document/permit/MDE-LMA-PER066.pdf for more details (webpage accessed February 6, 2013) 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-5 

and abandoned), orphaned gas or oil wells, caves, caverns, Karst features, etc.; (2) identification 

of all ecological, recreational, historical, and cultural resources in the vicinity of a proposed site 

(includes well pad and all ancillary development such as cleared areas around a well pad, roads, 

bridges, culverts, compressor stations, pipelines, etc.); (3) identification of all appropriate 

setbacks and buffers for the proposed site; and (4) collection of two years of pre-development 

baseline data on underground sources of drinking water, downstream surface water, and both 

aquatic and terrestrial ecological resources. Several of these aspects of environmental assessment 

are already required under Maryland’s existing oil and gas regulations, but other elements will 

need to be added.7

 Additional details on on-site and off-site monitoring to address MSGD 

impacts are provided in the following section. 

B. On-site and off-site monitoring 

On-site and off-site monitoring is an important aspect of MSGD that has not yet received the 

attention that the subject deserves. Environmental monitoring in the context of MSGD could play 

one or several important and legitimate roles, although generic monitoring would be unlikely to 

serve any particular purpose (except the purpose of making the citizenry of the state feel that 

resources are being adequately protected because they are being “monitored”). Too often, 

monitoring systems are put in place at great expense without carefully considering how 

monitoring data would actually be used. Depending on the specific types and ways that data are 

collected, monitoring can clearly address: 

• environmental regulation (ensuring compliance with or documenting violations of 

standards and regulations);

• environmental remediation (establishing a benchmark for assessing damages and 

performing reclamation or restoration activities);

• environmental science (increasing process-level understanding, especially when 

combined with research); and 

• environmental control (detecting problems and providing feedback to the process of 

defining best management practices) 

There are virtually no comprehensive, carefully-designed, experimental studies of the impacts of 

MSGD on environmental resources that have been published in the literature, so scientific 

observations of actual impacts (or no impacts) associated with MSGD through case studies could 

play an important role in gaining process-level understanding (USEPA 2011)8

. To date, most 

monitoring efforts have been associated with obtaining baseline water quality data from nearby 

groundwater wells that could be used to assess future damages from development activities, 

particularly hydraulic fracturing. Given that the risks to surface water quality from chemical or 

wastewater spills or releases are considered at least as great as those to groundwater, greater 

attention should be paid to benchmarking surface water quality (and continued monitoring to 

enable detection of water quality deterioration). However, almost no attention has been paid to 

 

7

 COMAR 26.19.01 

8

 The U.S. Environmental Protection Agency’s ongoing study of the possible impacts of hydraulic fracturing comes 

closest to a systematic study, but it is addressing a limited number of possible impacts (drinking water resources) 

and has not been completed or published. Sadly, the recently released progress report in December 2012 (USEPA 

2012) described a series of case studies in which many of the empirical data that would be used to test and 

parameterize impact models were collected after MSGD had already occurred (i.e., little or no pre-development 

data are available). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-6 

the use of monitoring data in improving best practices for shale gas development (USDOE 

2011)9

. In fact, many of the BMPs that we have identified in this report are based primarily on 

professional judgment rather than on systematic experimental testing with replication under a 

variety of field conditions. Our review revealed that relatively little monitoring has been done to 

establish baseline resource conditions prior to MSGD and subsequent monitoring of impacts may 

be only marginally useful. The best example of monitoring that we found is the program being 

developed and implemented by Pennsylvania Department of Conservation and Natural 

Resources (PADCNR) to address impacts of MSGD in the Pennsylvania state forests (PADCNR 

2011). While this program certainly has some significant merits relative to what is being done 

elsewhere, it is obvious that MSGD was well underway before this program was ever fully 

implemented (in fact, it has still not been fully implemented even today). 

Most of the baseline data that are presently being collected are for groundwater wells within a 

defined radius of a proposed gas well primarily to provide a benchmark for assessing damages 

(or as defense from presumed liability in the event that contamination is detected in the future). 

In Pennsylvania, for example, private water wells located within 1,000 ft of a proposed gas well 

are tested before drilling as part of the permitting process. Well monitoring in Pennsylvania 

showed post-drilling increases in bromide (Br) concentrations, suggesting that 3,000 ft is a more 

reasonable distance than the 1,000 ft that is currently required for both presumed responsibility 

and certified mail notification related to Marcellus gas well drilling (Boyer et al. 2011). Few, if 

any, hydrogeologists would disagree with the conclusion that sampling water wells within a 

3,000 ft radius of a gas well is a pretty marginal groundwater monitoring program if the intent is 

to be able to detect a subsurface contaminant plume associated with a particular well integrity 

issue (especially in rural areas where the number of water wells may be very low or zero). 

Other resources that could be impacted by development of a particular site (e.g., surface water 

quantity and quality, air quality, forest interior bird populations, etc.) have received even less 

attention, however. It is, therefore, recommended that Maryland require as part of its permit 

application at least two years of site-specific data collection prior to any site development that 

would be used to characterize the resources at risk and provide a solid baseline dataset that 

would ultimately be used to understand process and feedback useful information for refinement 

of BMPs. These data should be collected at operator’s expense and reported to Maryland 

Department of the Environment (MDE) as part of the permit application process. Although 

providing a detailed site-specific monitoring plan for MSGD is well beyond the scope of this 

project, we can provide some rough guidelines for what might constitute a realistic plan: (1) the 

monitoring system should be designed in a way that characterizes the extent of any site-specific 

impacts on- and off-site (e.g., downstream of a particular well pad; groundwater well sampling at 

least to the periphery of the area defined by the lateral boreholes); and (2) frequency of data 

collection should be adequate to quantify natural variability of conditions (e.g., monthly 

sampling of surface water may be appropriate, but annual sampling of groundwater quality may 

suffice). A draft plan that we obtained from Maryland DNR contains many of the elements that a 

solid, site-specific water and macro-invertebrate monitoring plan would likely include (Klauda et 

 

9

 The report explains that developing reliable metrics for best practices for shale gas development is a major ongoing task, and further advised that the industry set a goal of “continuous improvement” in best practices that 

would be “validated by measurement and disclosure of key operating metrics”. Such validation would likely be 

heavily based on the collection and analysis of on-site and off-site monitoring data of specific parameters. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-7 

al. 2012). We envision that on-site and off-site monitoring would be continued through the life of 

the project as a means of assessing impacts, improving BMPs, and providing some process-level 

understanding of how resources are being affected. 

Regional monitoring of environmental resources by the state is also recommended. In particular, 

both air quality and water quality may be impacted by cumulative MSGD over the entire region 

(or within a portion of the region), so a monitoring network will need to be established to address 

cumulative impacts both before and after development begins. As examples, the proposals to 

sample methane (and other constituents) in a sample of drinking water wells in western 

Maryland is an excellent idea that should be funded; comparable surveys of surface water quality 

in specific western Maryland watersheds that are likely to experience MSGD would be equally 

useful in establishing a regional baseline. Finally, air quality impacts are likely to occur at the 

regional scale, so MDE should ensure the one existing air quality monitoring station in the region 

is equipped with instrumentation to address primary MSGD impacts (e.g., NOx, VOC, and fine 

particulate concentrations). While the design and implementation of this monitoring network is 

crucial, it may not be necessary to build such a system from scratch. Many of the monitoring 

components can probably be piggy-backed onto existing monitoring and resource assessment 

activities (e.g., MBSS) that the state is presently conducting for other purposes. 

C. Comprehensive drilling plans (CDP) 

One way of attempting to minimize some of the most significant negative impacts associated 

with developing gas resources within an area (and possibly moderating the rate at which the 

resource is developed) is through a process known as comprehensive planning. It is thought that 

by carefully mapping the “constraints” on gas development presented by a variety of 

environmental and socioeconomic factors and also identifying the foreseeable oil and gas 

activities in a defined geographic area upfront, energy companies working cooperatively with 

other stakeholders (including state natural resource agencies) can come up with an integrated 

plan for efficiently exploiting the resource while minimizing impacts on local communities, 

ecosystems, and other natural resources. Under a COGCC rule10, gas operators in Colorado have 

the option of proposing a Comprehensive Drilling Plan (CDP)11 that covers multiple drilling 

locations within an area as a way of addressing some of these constraints; while voluntary, CDPs 

are definitely encouraged in Colorado and it has been concluded that the process would work 

better if operators would work together to develop a joint CDP to cover proposed activities of 

multiple operators where appropriate. Presently, one major operator is in the process of 

developing a CDP for 11 well pads and 200 gas wells in the Battlement Mesa area in Garfield 

County, CO—a community that is home for about 5,000 residents12. Given the fact that western 

Maryland is a largely intact landscape with areas of high terrestrial and aquatic biodiversity and 

known surface resources that are in need of special protection, a comprehensive gas development 

plan makes a lot of sense. Comprehensive planning could potentially be used to effectively 

 

10 Rule 216, 2 CCR 404-1 Practice and Procedure 

11 The term comprehensive drilling plan (CDP) is actually somewhat of a misnomer. A better term would be 

“comprehensive gas development plan” because it would logically include all aspects of the activity (i.e., 

constraints mapping for resource protection, exploration, environmental monitoring, drilling/fracking, gas 

transmission, transportation, planned mitigation of impacts, etc.). 12 See http://www.oilandgasbmps.org/resources/casestudies/battlementmesa.php (webpage accessed February 6, 

2013) 
K.N. Eshle

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Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-9 

gradually developing the appropriate experience over time that plays and essential role in 

ensuring that development is conducted as safely as possible. In Pennsylvania, for example, it 

took several years to staff a regulatory program within the Department of Environmental 

Protection (PADEP) and PADCNR to effectively address MSGD on both private and public 

lands. As of summer 2012, PADCNR alone had a 50 person “gas management team” that is 

responsible for managing the program in the state forests13, in addition to the large number of 

inspectors in PA DEP that enforces permit conditions throughout the state. It is generally 

accepted that many of the problems that have occurred in Pennsylvania and elsewhere can be 

explained in part by the excessively rapid rate of MSGD before the necessary regulatory 

structure had been put in place. 

Comprehensive drilling plans are also being used in Pennsylvania state forests and have been 

proposed for private lands in the state (Lien and Manner 2010); these plans involve significant 

interactions (“give and take”) between the energy companies, state regulators, local authorities, 

and the public at large to get all of the various stakeholders on the same page. Through this give 

and take process, gas development infrastructure should be planned for in advance, even if full 

implementation ultimately takes many years. While we favor this approach in general, we have 

some reservations as to whether Maryland’s regulatory structure and culture are sufficiently 

flexible to enable such an approach to be effectively implemented. 

Another major impediment to comprehensive gas development planning in Maryland is that the 

state lacks the power to do “forced pooling” (or “compulsory integration” or “unitization”)14. 

With forced pooling, a gas company could force one or more entities with ownership of the 

mineral rights of some portion(s) of a gas “unit” into a lease in order to enable more efficient 

exploitation of the resource (perhaps while providing greater protection of some specific surface 

resources overlying a portion of the unit). The practice of forced pooling is controversial and has 

been considered an infringement of property rights (the current Governor of Pennsylvania has 

called forced pooling “private eminent domain”15). Thirty-nine states have some type of forced 

pooling law, but Maryland does not. This power is particularly important given the practice of 

horizontal drilling, since the technology itself makes it possible to capture gas thousands of feet 

(horizontal direction) from a wellhead (e.g., gas resources underlying sensitive surface resources 

that would otherwise be impossible to extract without causing undesirable disturbances). 

Drilling companies have argued that forced pooling effectively enables more gas to be extracted 

from fewer well pads—thus reducing costs and environmental impacts. Without the power to 

enforce a forced pooling arrangement proposed by a drilling company, however, Maryland 

effectively lacks a planning tool that could be used to provide greater resource protection while 

allowing for efficient resource exploitation. It is not clear to us whether forced pooling would be 

acceptable in Maryland, given the state’s legal approach to mineral rights; nonetheless, it is a 

topic that should be further examined. 

 

 

13 Ibid., 5 

14 Brigid Kenney (Maryland Department of the Environment), personal communication (December 3, 2012). 15 Reported by ProPublica: http://www.propublica.org/article/forced-pooling-when-landowners-cant-say-no-todrilling (webpage accessed December 3, 2012) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-10 

D. Well pad spacing 

Our research suggests that modern horizontal drilling and hydraulic fracturing from multi-well 

pads are presently capable of draining at least one or perhaps as much as two square miles of the 

target formation (see hypothetical example in Figure 1-1)—thus enabling the siting of well pads 

at locations that can avoid sensitive resources and greatly minimize disturbances and associated 

impacts on both terrestrial and downstream aquatic ecosystems from development. Spacing 

multi-well pads in dense clusters—with well pads located as far apart as is technically feasible—

makes maximum use of horizontal drilling technology and could be an important BMP in terms 

of minimizing development impacts. Figure 1-2 shows an air photo of such a multi-well, multipad development in Pennsylvania, illustrating how the extent of surface disturbance can be 

minimized using this BMP. Further, our analysis suggests that—with careful and thoughtful 

planning (e.g., co-location of infrastructure wherever possible)—it may be possible to develop 

much of the gas resource in a way that disturbs less than 1-2% of the land surface, even when 

accounting for the need for ancillary infrastructure such as access roads, pipelines, and 

compressor facilities. While this may be a “best case” scenario and there is probably no definable 

threshold of land disturbance below which zero impacts would be expected, it should be 

emphasized that disturbances of 1-2% of the land surface are quite low compared to other types 

of development (e.g., suburban residential, surface mining, etc.). 

Figure 1-2. Air photo showing a densely-clustered well pad development in Pennsylvania. Drilled Marcellus gas 

wells are identified as red dots. Screen shot from web-based map viewer at http://maps.tnc.org/paenergy/ developed 

by The Nature Conservancy (website accessed February 8, 2013). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-11 

We also note that clustered well pad development can only be expected to reduce surface 

impacts if operators are held to reasonable spacing dimensions over time. In the Pennsylvania 

state forests, operators have agreed to drill wells as reasonably prudent as possible—although not 

all leases had well spacing limitations. Newer leases hold operators to a maximum number of 

well pad locations, or total disturbance of a predefined acreage, whichever occurs first. In these 

leases, if an operator wishes to deviate from the well pad numbers or acreage, a waiver and state 

forest approval is required (PADCNR 2011). Minimizing the number and density of well pads 

through coordinated planning and consultation (i.e., a CDP), as well as utilization of existing 

rights of way, can greatly mitigate the cumulative impacts on the landscape (Marcellus Shale 

Advisory Commission 2011). Given that the well pad and ancillary infrastructure will likely be 

in place for at least a 30-year period before final reclamation can be completed, we recommend 

that Maryland guard against any tendency for infilling (i.e., drilling from new pads that expands 

the density of the surface infrastructure within an area) by incentivizing drilling of any new wells 

from existing pads once these are permitted. Our concern here is for minimizing cumulative 

impacts that may likely prove to be a function of the total amount of surface development within 

an area. 

E. Setback requirements 

Setbacks are a primary tool by which regulatory agencies can restrict shale gas development in 

an effort to provide some additional protection of the most sensitive ecological resources, water 

resources, personal property, public property, and the health and safety of the public at large 

particularly in the event of an accident (e.g., pollutant spill, blow-out, etc.) during the conduct of 

shale gas development operations. How much protection (if any) these setbacks can provide can 

clearly be debated; many setbacks do not seem to be based on solid scientific reasoning or 

empirical data. Nevertheless, both industry and the state benefit when setbacks are clearly stated 

in statutes or regulations. Setbacks that are vague or that depend on subjective site analysis 

introduce uncertainty into the decision-making process, leading to hidden costs (redundant 

analyses at best and legal fees at worst). Setbacks can sometimes be voided if landowner 

permission is obtained (e.g., setbacks from property lines), however they are sometimes used to 

protect the rights of other leaseholders. Variances from setback requirements can also be granted 

by regulatory authorities (typically if operators propose more stringent protective drilling and/or 

operational practices). It should be noted that the efficacy of setbacks in providing protection for 

streams may be especially questionable, given the fact that the network of “blue-line” streams 

that appears on 71⁄2 minute topographic maps may significantly underestimate the surface water 

resources at risk, especially small streams (Elmore et al. in review). 

Table 1-1 provides a summary of the recommended setbacks to provide protection of specific 

resources in Maryland, with justification and explanation following in the appropriate chapters of 

the report: special siting criteria (Chapter 1); water resources (Chapter 4); terrestrial habitat and 

wildlife (Chapter 5); aquatic habitat and wildlife (Chapter 6); public safety (Chapter 7); cultural 

and historic values (Chapter 8); quality of life and aesthetics (Chapter 9); and agriculture and 

grazing (Chapter 10). In each case, wherever two or more setbacks apply, the most restrictive 

setback would take precedence. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-12 

Table 1-1. Summary of recommended setbacks for resource protection and public safety.

From To Distance Chapter 

Aquatic habitat (defined as all streams, 

rivers, seeps, springs, wetlands, lakes, 

ponds, reservoirs, and floodplains) 

Edge of drill pad 

disturbance 

300 ft Chapter 5 and 6 

Special conservation areas (e.g., 

irreplaceable natural areas, wildlands) 

Edge of drill pad 

disturbance 

600 ft Chapter 5 

All cultural and historical sites, state and 

federal parks, trails, wildlife 

management areas, scenic and wild 

rivers, and scenic byways 

Edge of drill pad 

disturbance 

300 ft Chapter 8 

Mapped limestone outcrops or known 

caves 

Borehole 1,000 ft Chapter 1 and 5 

Mapped underground coal mines Borehole 1,000 ft Chapter 1 and 3 

Historic gas wells Any portion of the 

borehole, including 

laterals 

1,320 ft Chapter 1 and 3 

Any occupied building Compressor stations 1,000 ft Chapter 9 

Any occupied building Borehole 1,000 ft Chapter 9 

Private groundwater wells Borehole 500 ft Chapter 4 

Public groundwater wells or surface 

water intakes 

Borehole 2,000 ft Chapter 4 

F. Identification of freshwater aquifers and groundwater flowpaths 

Drilling for gas in the Marcellus shale formation (located 0 to 9,000 ft below the surface in 

western Maryland) will obviously require that operators drill vertical boreholes through the 

freshwater zone. Many western Maryland residents are dependent on groundwater for their 

drinking water16—underlining a critical need to identify and understand the hydrogeological 

setting and dynamics of the principal aquifers underlying this region prior to MSGD so that safe 

drilling practices that are protective of these systems can be implemented. The USGS reported 

that there are currently ten permitted water wells (mostly public supply wells) in the Deep Creek 

watershed in Garrett County with a reported combined average annual withdrawal of 0.28 MGD 

in 2007, plus an additional 2,900 permit-exempted individual wells with an estimated combined 

average annual withdrawal between 0.43 and 0.87 MGD.17 Withdrawals of groundwater for 

public supply increased by more than 2,000% between 1988 and 2007, reflecting both population 

growth and expanded public service in the watershed.18 An important issue is the depth that a 

surface well casing string must be placed and cemented to ensure that the fresh groundwater 

 

16 Estimated average daily withdrawals for self-supplied domestic use and public supply distribution in these two 

counties in 2000 (the most recent year for which data are available) were 2.41 million gallons per day (MGD) of 

surface water and 4.01 MGD of groundwater. See http://md.water.usgs.gov/freshwater/withdrawals/#ga (webpage 

accessed December 4, 2012). 17 McPherson, W.S. Water use in the Deep Creek Lake watershed, Garrett County, Maryland, 1980-2007; 

http://md.water.usgs.gov/deepcreek/wateruse/index.html (webpage accessed December 4, 2012). 18 Ibid. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-13 

resources can be adequately protected in the Deep Creek watershed and elsewhere. 

Subsequently, gas wells will have to be properly cased and cemented to protect fresh 

groundwater supplies (see Chapter 3). While many neighboring states have mapped the interface 

between saline and freshwater aquifers, Maryland has not. Water quality data from eight 

different projects conducted in the Northern Appalachian Coal Basin indicated total dissolved 

solids (TDS) levels between 2,000 and 5,000 milligrams per liter (mg/L) at depths ranging from 

500 to 1,025 feet below the ground surface—values that are within USEPA's water quality 

criterion (< 10,000 mg/L TDS) for underground sources of drinking water (Zebrowski et al. 

1991). It was reported that one deep well drilled in southern Garrett County encountered a 

freshwater/saltwater interface at a depth of 940 feet (Duigon and Smigaj 1985). 

We were unable to find detailed digital maps of the principal freshwater aquifers of western 

Maryland, nor hydrogeological cross-sections or quantitative data that could be used to develop 

flow nets or models to infer groundwater flowpaths and other important features such as recharge 

areas, discharge areas, hydrologic residence times, and depth of the freshwater zone across the 

area. The best resource appears to be a USGS report that includes a fairly detailed description 

and map of the principal aquifers of the area, plus some qualitative analysis of groundwater 

flowpaths and quality (Trapp, Jr. and Horn 1997). There is a definite need for a comparable 

hydrogeological analysis focused strictly on western Maryland that could be based on 

measurements of static water levels from domestic and commercial wells, well water quality 

data, and observations reported in well logs; a map of the freshwater/saltwater interface would be 

a useful product from such an analysis. Provided with adequate resources, the Maryland 

Geological Survey (MGS) might be the logical group to undertake such an investigation. 

The principal aquifers of unglaciated western Maryland include: (1) Appalachian Plateau 

aquifers in Paleozoic sedimentary rocks that are usually flat-lying or gently folded (especially 

sandstones of Pennsylvanian and Mississippian age and carbonate rocks of Mississippian age); 

and (2) Valley and Ridge aquifers that are often heavily folded (Paleozoic fractured sandstones 

and limestones are typically the most productive aquifers in these rocks). In the Appalachian 

Plateau in western Maryland, the principal aquifers have been identified as belonging to the 

Monongahela Formation, the Conemaugh Formation, the Allegheny-Pottsville Group, the Mauch 

Chunk Formation, the Pocono Formation, and the Greenbrier Formation (the latter is a limestone 

formation that is only locally water-yielding). The Monongahela, Conemaugh, and Allegheny 

Formations each contain multiple seams of mineable coal—most of which are economically 

important (Staubitz and Sobashinski 1983). In the Valley and Ridge of western Maryland, the 

principal aquifers are the Hampshire Formation, the Chemung Formation, and the Romney 

Group overlying the Oriskany Sandstone which is commonly saline (Trapp, Jr. and Horn 1997); 

coal seams are not considered mineable. 

In the Appalachian Plateau Province it has been suggested that groundwater flow is “step-like”—

following vertical pathways through fractures and horizontal pathways through fractured 

sandstone aquifers and coal beds. Groundwater recharge in the province is thought to be fairly 

low, owing to the relatively steep topography and shallow regolith. The low permeability shales 

underlying the Appalachian Plateau Province function as confining beds that can often give rise 

to flowing Artesian conditions in wells penetrating aquifers below the shales; this often occurs in 

wells located in the synclinal valleys of the province. Even in areas where groundwater has not 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-14 

been impacted by earlier oil and gas development that began as early as the 19th century, saline 

water can be encountered in aquifers within just a few hundred feet (or less in some cases) of the 

ground surface. Hydrogeologists have attributed this situation to (1) the presence of nearly flatlying low permeability strata of shales, siltstones, clays, and dense limestone; and (2) the lack of 

intensely fractured formations that effectively prevent deeper circulation of freshwater to great 

depths below the surface. In other areas, however, shallow groundwater has been contaminated 

by brines that flowed upward under pressure through improperly cased or plugged oil and gas 

wells that penetrated deeper saline aquifers; there are other examples of fresh groundwater 

contamination from infiltration and percolation of brines stored in open pits (Trapp, Jr. and Horn 

1997). 

In the Valley and Ridge Province, it is thought that groundwater moves mostly along fractures 

and bedding planes, and in solution channels within carbonate rocks; the alternately folded 

sedimentary rocks, combined with a fluvially-dissected topography, have created a series of local 

groundwater flow systems that exist within the upper few hundred feet of the land surface and 

are effectively isolated from the intermediate and regional flow systems below. Springs 

(including both gravity springs from unconfined aquifers and Artesian springs from confined 

aquifers) are also very common in the Valley and Ridge. Thermal springs are also well known in 

the province (e.g., including famous Berkeley Springs, WV and Warm Springs, VA) where 

deeper heated groundwater is effectively channeled back to the surface by folding, faulting, and 

fracturing of the confined aquifers (Trapp, Jr. and Horn 1997). It appears that these “warm” 

springs form on the crests or limbs of anticlines, particularly where vertical permeability is 

enhanced at openings along bedding planes, tension fractures, open faults, or other fractures 

common to folded structures (Hobba, Jr. et al. 1979). Thus, there definitely are hydrogeological 

pathways by which groundwater heated at great depths (i.e., several thousand feet below the 

surface) flows upward through fault or fracture systems under pressure and discharges at surface 

springs in the Valley and Ridge Province. White Sulfur Spring and Black Sulfur Spring in Green 

Ridge State Forest may be less well-known examples of this same phenomenon. 

A major concern with hydraulic fracturing is that fractures may propagate vertically upwards 

into the freshwater zone (or intersect with natural fractures), thus increasing the communication 

between the target gas formation and underground sources of drinking water (USDW), thus 

providing a mechanism for contamination of drinking water sources. We couldn’t find any 

conclusive studies documenting contamination of USDW by this mechanism; one fairly 

extensive study investigated hundreds of alleged occurrences of this phenomenon from 

hydraulically-fractured coal bed methane (CBM) deposits without drawing much of a conclusion 

(USEPA 2004). With respect to CBM wells, the consensus seems to be that there are two distinct 

mechanisms by which groundwater contamination could occur: (1) direct injection of hydraulic 

fracturing chemicals into a CBM formation that is in direct communication with USDW; or (2) 

creation of a hydraulic communication between a coal seam and an overlying or underlying 

aquifer by breaching a confining layer that provides natural isolation of the CBM from USDW 

(USEPA 2004). 

Therefore, at least until it can be shown that hydraulic fracturing can be done safely within 

relatively close proximity to USDW, we recommend that Maryland follow guidance from New 

York’s experience in regulating unconventional shale gas development and effectively not 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-15 

permit MSGD (or any other unconventional gas development) where the target formation occurs 

within 1,000 vertical feet of USDW or within 2,000 vertical feet of the ground surface 

(NYSDEC 2011). While the stratigraphy of New York’s Marcellus region is certainly not 

identical to Maryland’s (the most obvious example is that New York’s landscape was mostly 

glaciated during the Pleistocene, effectively removing many of the Pennsylvanian sedimentary 

formations from the profile), the basic stratigraphy of the Devonian formations is quite similar 

(Kostelnik and Carter 2009). Since the freshwater/saltwater interface has not been mapped in 

Maryland, the prudent approach would be to rely on the 2,000 ft criterion to provide a reasonable 

margin of safety. As discussed in Chapter 3, a recent report shows data from several thousand 

hydraulic fracturing treatments that had been mapped in the Barnett shale in Texas using a 

micro-seismic method that purportedly indicate that the closest a vertical fracture came to a 

USDW was 2,800 ft and the typical distance was nearly 5,000 ft; data from hundreds of 

fracturing treatments in the Marcellus shale displayed in the same report shows a similar result 

(Fisher 2010). An important limitation of this interpretation is that neither analysis included any 

micro-seismic measurements where the target shale formation was within 4,000 ft of the surface. 

On the other hand, rock mechanics theory suggests that a hydraulic fracture will propagate in a 

direction that is perpendicular to the least principal stress. In shallow (i.e., < 1,000 ft) formations, 

the least principal stress is likely the overburden stress—so hydraulic fractures would be 

predicted to propagate primarily in the horizontal direction. In deeper reservoirs, however, the 

least principal stress would likely be horizontal and hydraulic fractures would thus be expected 

to propagate vertically (USEPA 2004). In Chapter 4 we discuss methods by which vertical 

propagation of fractures can be estimated. 

G. Stakeholder engagement (e.g., education, town hall meetings, local 

community interactions, landowner and lessor protections) 

Despite recommendations by the American Petroleum Institute (API) that operators proactively 

engage both surface owners and surface users before MSGD operations are initiated to foster 

understanding and alleviate concerns about hydraulic fracturing and other activities (API 2009), 

we found very few examples of novel approaches to ensuring that such engagement actually 

takes place. API recommends that operators communicate with land owners and/or surface users 

concerning activities planned for a particular site and provide information on the measures to be 

taken for safety, protection of the environment, and minimizing impacts to surface uses. We 

definitely support these recommendations, but feel strongly that this activity should go far 

beyond posting a notice in a local newspaper, which may not have the circulation of other media. 

State agency websites can be informative, but better approaches to stakeholder engagement 

would be through public forums or perhaps even via social media (e.g., Facebook). The goals of 

any interactions should be for transparency and increasing the flow of timely and relevant 

information to surface owners, users, and other stakeholders. As recommended for Pennsylvania, 

Maryland might consider developing a standardized stakeholder process that could be 

implemented as part of a comprehensive planning strategy; the goal of such a process would be 

to engage stakeholders and the community in the most effective ways possible, while allowing 

the permit review process to be expedited (Ubinger et al. 2010). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-16 

H. Special siting criteria 

The practice of identifying and using special criteria for siting well pads within a region is based 

on the idea that some natural (e.g., geological, hydrological, etc.) or man-made (e.g., 

underground mining) factors may significantly increase specific risks associated with shale gas 

development; efforts could be made to identify such criteria prior to developing the gas resource 

so that operators and regulatory authorities can make use of such information during the permit 

application and review process. One such restriction is the topography; well pads should be sited 

on land with a slope of <15%. Much of western Maryland exhibits steep and rugged terrain that 

exceeds this slope recommendation (Figure 1-3). Steep topography increases risks associated 

with spills, sediment and erosion pollution, and natural hazards (landslides). While increasing the 

cost associated with MSGD, some operators might be tempted to drill on steep slopes. However, 

in conversations with industry representatives, we learned that most MSGD operators avoid 

slopes greater than 15%, likely making this recommendation moot19. 

Highly permeable subsurface zones—including both natural subsurface reservoirs (e.g., caves, 

caverns, and fractures) and man-made voids (e.g., underground mines and abandoned wells)—

can provide preferential pathways by which aqueous or gas-phase contaminants could rapidly 

migrate away from a site in the event of a casing or cementing failure. Moreover, such voids 

present technical challenges and safety issues both in drilling (i.e., lost circulation of drilling 

fluids that could cause borehole collapse), in maintaining well control (i.e., avoiding a blowout), 

and in ensuring well integrity during and following cementing operations (Abbas et al. 

2003/2004). Voids are very commonly encountered when drilling in southwestern 

Pennsylvania20, necessitating the use of remedial cementing (i.e., cement “squeezes” from the 

surface, rather than normal cementing in which cement is pumped under pressure down the 

casing and back up to the surface through the annular space, displacing non-cement fluids and 

establishing a bond with the casing and the borehole wall). Cement squeezes (i.e., grouting of the 

annular space by pouring cement from the surface) are very time-consuming, expensive, and—

most importantly—have a very low success rate and can leave a portion of the surface casing 

string unprotected from corrosive fluids (Abbas et al. 2003/2004). 

To address these issues, the recently enacted Horizontal Well Act (H.B. 401) required the 

Secretary of the West Virginia Department of Environmental Protection to: 

propose emergency and legislative rules pertaining to drilling in karst formations, establish designated 

geographic regions of the state where these provisions of the act are applicable, and establish standards 

for drilling horizontal wells in naturally occurring karst terrain. Drilling horizontal wells in naturally 

occurring karst terrain may require precautions not necessary in other parts of the state; such additional 

safeguards may include changing proposed well locations to avoid damage to water resources, special 

casing programs, and additional or special review of drilling procedures. At a minimum, the act requires 

operators to perform certain predrilling testing to identify the location of caves and other voids, faults 

and relevant features in the strata and the location of surface features prevalent in naturally occurring 

karst terrain such as sink holes; and provide any other requirements deemed necessary by the secretary 

 

19 Scott Rotruck, Chesapeake Energy, personal communication (April 27, 2012) 

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At the time of this report, spatial locations for 33 caves in Garrett and Allegany counties were 

available. These locations are aligned along relatively narrow bands in the vicinity of where 

limestone units crop out at the surface (Figure 1-4) with two locations falling outside of a 1000 ft 

buffer surrounding outcropping limestone units. Because cave systems are inherently difficult to 

find and map, estimates are that only 10% of caves in western Maryland are known23. Drilling in 

the vicinity (i.e., within 1,000 ft) of outcropping limestone should be considered a serious risk 

throughout the entire extent of limestone in western Maryland24. However, due to horizontal 

drilling techniques it should be possible to avoid drilling through these highly permeable 

formations and voids (both mapped and unmapped)—thus avoiding some of the most serious 

risks associated with poor well cementing that compromises well isolation and integrity. 

Consistent with the suggested requirements under H.B. 401, an obvious best practice for 

Maryland would be to site well pads so as to avoid vertical drilling (i.e., surface boreholes) in 

areas where shallow caves and caverns have been mapped or where there is a high probability 

that such systems might be present. In cases where caves or underground voids are unexpectedly 

encountered during drilling, the technical approaches outlined by Abbas et al. (2003-04) to 

ensure well isolation should be carefully applied. The technical capability to drill horizontal 

lateral wells many thousands of feet long under such cave systems may allow the shale gas 

resource to be extracted in a way that significantly minimizes the risks described above. 

We have comparable concerns about MSGD in areas with extensive underground coal mine 

workings (both abandoned and active), gas storage fields (e.g., the Accident Gas Storage Field), 

and/or existing and/or orphaned oil and gas wells (see Figure 1-5). Western Maryland has a long 

history of underground coal mining in each of five different fields (the Lower Youghiogheny 

field, the Upper Youghiogheny field, the Potomac field, the Georges Creek field and the 

Casselman field) that has left a legacy of underground voids that present real challenges in terms 

of well isolation. Drilling in the vicinity of active underground coal mines represents an extreme 

hazard for a variety of reasons, most importantly the safety of workers who could be exposed to 

flammable and poisonous gases released into mine workings during the drilling process. Further, 

casing through these voids would require cement “squeezes” from the surface that are subject to 

failure. Finally, steel casing could be subjected to corrosive acid mine drainage (AMD) that 

might be present in abandoned underground workings, possibly leading to a catastrophic casing 

failure over time. For these reasons MSGD should be avoided in areas with known underground 

mine workings; we recommend the same 1,000 ft buffer around known workings to provide the 

additional margin of safety that was recommended for drilling in Karst terrain25. 

 

 

23 Ibid. 

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the mapped limestone formations; and (2) since caves in the Greenbrier formation in Garrett County are expected 

to be confined to a weathered zone within 200 ft of the surface and the dip of these formations is approximately 

20° (from the horizontal), a setback on the down-dip side of 550 ft [L = 200 ft/tan(20°)] should be adequate. Since 

the dip of limestone beds in Allegany County is even steeper, a setback of 550 ft would suffice. The 1,000 ft buffer 

on both sides provides an additional margin of safety due to uncertainties about the exact location of these 

outcrops. 25 This additional margin of safety is justified, in part, due to the fact that the digital layer of underground mines that 

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K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

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coal bed methane wells, and gas seeps and springs within two miles of such wells. COGCC 

maintains a GIS map system that has a data layer showing bottomhole locations that the staff 

includes in their review of historic plugged and abandoned wells within 1⁄4 mile (STRONGER 

2011). An important best practice will be for Maryland to require setbacks from areas of 

previous deep coal and gas extraction. Maryland should develop a GIS of both active and 

abandoned oil and gas wells (including gas storage wells) and active and abandoned coal mine 

workings prior to permitting any new Marcellus wells. All underground hazards within 1⁄4 mile of 

any section of a proposed Marcellus well should be identified as part of the permit review 

process. We recommend a 1,320 ft (1⁄4 mile) setback from all historic gas wells. 

Figure 1-5. Mineral resource extraction in Maryland includes deep coal mines (both active and abandoned) and 

active and historic conventional gas wells. Data on abandoned and active deep coal mines, and active and historical 

gas wells was provided by Maryland Department of the Environment. The boundary of the Accident Storage Field 

was digitized from paper maps provided by Spectra Energy of Texas Eastern Transmission, LP. The size of the 

symbols representing the locations of gas wells have been adjusted to closely match the recommended setback of 

1,320 ft provided in Table 1-1. 

In addition to avoiding underground voids through implementation of these setbacks, Maryland 

might also consider mandating the use of surface geophysical techniques (e.g., seismic surveys) 

or “pilot hole” boring as part of an exploration/drilling hazard assessment program that is aimed 

at identifying other subsurface MSGD hazards that are not well mapped. 

I. Reclamation planning 

Another very important conclusion from our review of the literature and of activities in other 

states is that for planning purposes, MSGD infrastructure should be considered a quasi-
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-21 

permanent (i.e., at least 30 years) industrial addition onto a mostly rural Appalachian landscape. 

We have drawn this conclusion because: a) Marcellus wells are expected to produce for at least 

30 years; b) it may be possible to refracture these wells in the future to enhance diminishing gas 

production; c) wells on multi-well pads may not be drilled in rapid succession to allow 

companies the ability to determine if additional drilling is warranted and justified financially; 

and d) established pads and associated infrastructure could possibly support future 

unconventional drilling into the Utica formation. In the Tiadaghton State Forest in Pennsylvania, 

for example, we observed that no permanent site restoration or reclamation has occurred or is 

planned (Figure 1-6) despite the fact that the drilling/hydraulic fracturing equipment had all 

moved on by the time wellhead gas prices had plummeted to less than $3 per thousand cubic feet 

in early 2012 (from a peak of nearly $11 in July 2008; see Figure 1-7). The thinking there is that 

many of the most serious impacts (i.e., erosion and stream sedimentation) are associated with 

earth moving and construction activities, so it makes sense both economically (for the gas 

companies) and environmentally (for the state) to maintain the established infrastructure rather 

than imposing conditions that would require multiple reclamation efforts over time at the same 

sites. 

The quasi-permanent superposition of this industrial infrastructure onto the landscape and 

associated time delays until any permanent site restoration, reclamation, and well plugging takes 

place has important implications for how states regulate MSGD now to ensure that liabilities for 

reclamation and closure are properly addressed by the gas industry. The best practice for 

Maryland would be to develop regulations that force rapid partial reclamation (including 

revegetating disturbed areas surrounding wells pads, corridors, and ancillary infrastructure) of all 

land not needed for drilling and production as quickly as possible, while allowing the remaining 

portion to exist unreclaimed only until such time as drilling is completed, production ends, and 

final reclamation can be performed. We feel strongly that the costs of reclamation should be 

borne directly by the operators (using resources set aside or accumulated for this specific 

purpose)—as opposed to ultimately passing these costs on to Maryland residents in the form of 

future tax liabilities and diminished natural and environmental resources (see discussion of 

financial assurance in Section J below). 

J. Well permitting, county and state coordination, and financial assurance 

Based on our review of practices in other states, it is obvious that MSGD in Maryland should 

require approval of a drilling permit issued by the state that addresses all possible issues 

associated with developing a particular site, drilling and completing a well (or wells), preventing 

erosion and sedimentation impacts, controlling stormwater pollution, protecting public safety, 

and responding to emergencies) and a mechanism for providing adequate financial assurance for 

decommissioning (plugging a well or wells), site reclamation, and any legacy responsibilities 

associated with a particular operation. All five states that we reviewed require permits and 

bonding for drilling gas wells, but the permitting and bonding requirements vary drastically 

among the different states. We found that Maryland’s current oil and gas regulations governing 

permitting for conventional development require many of the elements that would be needed to 

properly address MSGD or unconventional development in general including: (1) an 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-22 

 

environmental assessment; (2) a certificate of liability insurance; (3) a performance bond; (4) a 

copy of the oil and gas lease; (5) written approval by the local zoning authority that all planning 

and zoning requirements have been met; (6) an approved erosion and sediment control plan; (7) 

an approved stormwater management plan; (8) a reclamation plan; (9) a spill prevention, control, 

and countermeasures plan; and (10) a drilling and operating permit plat.29 Maryland’s current 

regulations even allow for directional drilling (although they were clearly not written to address 

the practice of hydraulic fracturing); the current statutes allow for the use of pits for temporary 

storage of drilling fluids, but do not explicitly address impacts of water withdrawals or 

wastewater treatment and disposal issues. The state should consider revising its oil and gas 

permitting regulations to explicitly address water withdrawal and storage issues, drilling waste 

and wastewater treatment and disposal issues, as well as transportation planning issues. 

 

29 COMAR 26.19.01.06 (Drilling and Operating Permit Application Procedures for the Applicant) 

Figure 1-6. Marcellus shale natural gas 

infrastructure in Tiadaghton State Forest near 

Waterville, Pennsylvania: well pad, multiple 

producing wells, and produced water tanks 

(upper left); shallow impoundment for 

freshwater (lower left); and access road, utility 

corridor, and compressor station (right). Photos 

by K.N. Eshleman. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-23 

 

Figure 1-7. Monthly U.S. natural gas wellhead prices (1975-2012); 

http://www.eia.gov/dnav/ng/hist/n9190us3m.htm (webpage accessed February 8, 2013). 

Local zoning could be used to avoid the most problematic conflicts among competing land uses 

in western Maryland, although zoning in Garrett County is not county-wide; it is restricted to a 

few municipal zoning districts (e.g., Deep Creek watershed). It does not appear to us that county 

zoning ordinances for Allegany County30 have been modified to explicitly address MSGD. 

Zoning ordinances for Deep Creek watershed in Garrett County surprisingly allow for “drilling 

for, or removal or underground storage of natural gas” in all nine zoning subdistricts (subject to 

prescribed minimum setbacks and regulations of MDE, Maryland Public Service Commission, 

and Federal Energy Regulatory Commission)31. It is not clear to us that Garrett County has 

carefully weighed the impacts of MSGD within its zoning districts, although current restrictions 

for Deep Creek watershed that restrict gas development within 1,000 ft of a property boundary 

and within 2,000 ft of the shoreline seem reasonably restrictive.32 Local zoning ordinances for 

both counties should be amended to spell out in which zoning districts MSGD would be 

permitted as a way of minimizing some of the major conflicts and public safety issues that we 

have identified in this report. 

With respect to performance bonding, Maryland’s requirements under current regulations 

($100,000 per well or $500,000 blanket bond for all of an applicant’s wells33) are relatively high 

compared to other states that we reviewed (e.g., Section 215 of Pennsylvania’s Oil and Gas Act 

set bonding limits at $2,500 per well or $25,000 for a blanket bond for drilling on private land 

(Ubinger, et al. 2010), although limits are higher for drilling in Pennsylvania state forests). 

Performance bonding has been deemed inadequate for providing financial assurance for 

addressing decommissioning, site reclamation, and legacy responsibilities associated with 

MSGD (Mitchell and Casman 2011). Mitchell & Casman (2011) used Pennsylvania’s experience 

 

30 Code of Allegany County Maryland, Part 4 Zoning (published November 25, 2002) 

31 Garrett County, Maryland; Deep Creek Watershed Zoning Ordinance (amended May 25, 2010) 

32 Ibid. 

33 COMAR 26.19.01.06.C(5)(a) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-24 

with bonding of surface coal mining sites to speculate what might be expected to occur with 

MSGD infrastructure in the absence of new regulations: from 1985 to 1999, bonds for surface 

mining permits covering about 10% of the total acreage of mineland in the state were forfeited. 

Since the costs to reclaim this mineland was in most cases higher than the bond amounts 

forfeited, the costs of bringing these abandoned minelands into compliance are inadequate and 

the difference must be made up by the responsible entity (in this case, the state, in some cases 

with help from the federal government’s abandoned mineland funds). 

While Maryland’s performance bonding limits are comparatively high, another concern is that 

steep declines in gas production of these wells in tandem with increasing liabilities for 

decommissioning and reclamation may drive divestment of shale gas assets before expected 

closure occurs. The transfer of marginally-productive assets to smaller independent operators or 

even to surface owners is a common practice in the oil and gas industry, with the primary 

exploration and production companies using these divestments to fund new drilling operations. 

At least in Pennsylvania (not sure about Maryland), there is no formal regulatory mechanism to 

prevent transfers of shale gas assets to entities under conditions in which the accumulated 

reclamation liabilities dwarf the financial wherewithal of the new asset owners—even though 

these new owners would also require bonding. In some cases, these firms can obtain surety 

bonds for only a percentage of a bond’s face value—putting much of the financial obligation on 

the backs of banks or surety companies who themselves would be liable for the reclamation costs 

down the road. Another problem with surety bonding is that underwriting firms will only market 

such bonds when the amount and terms of the liability are strictly defined; bonds are thus not 

well suited to covering unforeseen liabilities (e.g., legacy issues such as long-term replacement 

or treatment of a community’s water supply in the event that an existing supply is lost or 

irrevocably contaminated). Even in the event that the costs are covered prior to release of a bond, 

environmental problems that arise later would be difficult for individuals, communities, or a state 

to address without pursing a civil action (Mitchell and Casman 2011). 

We believe that Maryland’s relatively high bonding limits on oil and gas well drilling may 

largely prevent such divestments from occurring, and may also provide adequate funding 

through performance bonding to address all but the most catastrophic environmental impacts 

(e.g., loss of a community’s water supply, etc.). Typical costs of plugging Devonian shale wells 

and reclaiming sites in Pennsylvania are estimated to be somewhere in the range of $60,000 to 

$700,000 (mean of around $100,000) per well (with some economies of scale for plugging 

multiple wells on the same pad), so Maryland’s current bond limits appear reasonable (Mitchell 

and Casman 2011). Nonetheless, the state might wish to reexamine whether current bonding 

amounts (especially the blanket amount of $500,000) are adequate to address the full range of 

likely decommissioning costs. If the state is going to enforce the best practice of drilling 

multiple (e.g., six) wells from a single pad, it isn’t unlikely that a single operator could develop 

five pads (total of 30 wells) with a single blanket bond of $500,000 (less than $17,000 per well). 

Maryland might also consider alternate mechanisms of covering decommissioning and 

reclamation costs through a trust fund mechanism (i.e., investing revenue from pre-drilling fees 

and a five-year severance tax on production) as an alternative to bonding. The obvious downside 

to the state for such a mechanism is the case of the underperforming well (or dry hole) that 

would produce inadequate funding of the trust account. This problem could be solved fairly 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-25 

easily through the use of a pooled trust funded through revenue from multiple operators and by 

regularly adjusting the severance tax rate to ensure that the pooled fund is always adequate to 

cover the expected cumulative liability (Mitchell and Casman 2011). 

K. Key recommendations 

1-A Pre-development environmental assessment should be conducted on a site-specific basis 

and include: (1) identification of all on-site drilling hazards such as underground mine 

workings, orphaned gas or oil wells, caves, caverns, Karst features, etc.; (2) identification 

of all ecological, recreational, historical, and cultural resources in the vicinity of a 

proposed site (includes well pad and all ancillary development such as cleared areas 

around a well pad, roads, bridges, culverts, compressor stations, pipelines, etc.); (3) 

identification of the appropriate setbacks and buffers for the proposed site; and (4) 

collection of two years of pre-development baseline data on underground drinking water, 

surface water, and both aquatic and terrestrial ecological resources. 

1-B Maryland should require as part of its permit application at least two years of site specific 

data collection prior to any site development that would be used to characterize the 

resources at risk and provide a solid baseline dataset that would ultimately be used to 

understand process and feedback to the refinement of BMPs. 

1-C Comprehensive planning (a.k.a., comprehensive drilling plans) could potentially be used 

to effectively channel MSGD into areas that would be less sensitive to impacts while 

allowing for considerable and efficient exploitation of the gas resource. Spacing multiwell pads in clusters—as far apart as is technically feasible—makes maximum use of 

horizontal drilling technology and could be an important BMP in terms of minimizing 

development impacts. With careful and thoughtful planning (e.g., co-location of 

infrastructure wherever possible), it may be possible to develop much of the gas resource 

in a way that disturbs less than 1-2% of the land surface, even when accounting for the 

need for ancillary infrastructure such as access roads, pipelines, and compressor facilities. 

Comprehensive gas development plans could also moderate the rate at which the resource 

is developed in Maryland, thus allowing the regulatory enforcement arm of MDE (with 

little recent experience in gas well permitting and no experience in unconventional gas) 

to ramp up over time. 

1-D Maryland should consider legislation that would enable the state to implement “forced 

pooling” as a way of providing greater resource protection while allowing for efficient 

resource exploitation. 

1-E Maryland should impose by regulation sensible setbacks (see Table 1.1) that are adequate 

to protect public safety, as well as ecological, recreational, historical, cultural, and 

aesthetic resources. 

1-F There is a definite need for an analysis of extant hydrogeological data from western 

Maryland that could be used to develop flow nets or models and infer groundwater 

flowpaths and other important features such as recharge areas, discharge areas, 

hydrologic residence times, and depth of the freshwater zone across the area. 

1-G Maryland might consider developing a standardized stakeholder process that could be 

implemented as part of comprehensive planning strategy; the goal of such a process 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-26 

would be to engage stakeholders and the community in the most effective ways possible, 

while allowing the permit review process to be expedited. 

1-H We recommend that Maryland follow guidance from New York’s experience with 

unconventional shale gas development and effectively not permit MSGD (or any other 

unconventional gas development) where the target formation occurs within 1,000 vertical 

feet of USDW or within 2,000 vertical feet of the ground surface. Since the 

freshwater/saltwater interface has not been mapped in Maryland, the prudent approach 

would be to rely on the 2,000 ft criterion to provide an adequate margin of safety. 

1-I An obvious best practice would be to site well pads so as to avoid vertical drilling (i.e., 

surface boreholes) in areas where shallow caves and caverns have been mapped or where 

there is a high probability that such systems might be present. Maryland should develop a 

GIS map system of both active and abandoned oil and gas wells (including gas storage 

wells) and active and abandoned coal mine workings prior to permitting any new 

Marcellus wells; all underground hazards with 1⁄4 mile of any section of a proposed 

Marcellus well should be identified as part of the permit review process and avoided 

wherever possible. 

1-J Maryland should require a 1,000 ft setback from all deep mine workings and 1⁄4 mile 

setback from all historic gas wells. The gas well setback should be measured from any 

portion of the borehole (vertical or horizontal) to the historic well. 

1-K Maryland should develop regulations that force rapid partial reclamation (including 

revegetating disturbed areas surrounding wells pads, corridors, and ancillary 

infrastructure) of all land not needed for drilling and production as quickly as possible, 

while allowing the remaining portion to exist unreclaimed only until such time as drilling 

is completed, production ends, and final reclamation can be performed. 

1-L We found that Maryland’s current oil and gas regulations governing permitting for 

conventional development require many of the elements that would be needed to properly 

address MSGD or unconventional development in general; however, the state should 

consider revising its oil and gas permitting regulations to explicitly address water 

withdrawal and storage issues, drilling waste and wastewater treatment and disposal 

issues, as well as transportation planning issues. 

1-M Local zoning ordinances for both counties should be amended to spell out in which 

zoning districts MSGD would be permitted as a way of minimizing some of the major 

conflicts and public safety issues that we addressed in this report. 

1-N Maryland’s requirements for performance bonding under current regulations ($100,000 

per well or $500,000 blanket bond for all of an applicant’s wells) are relatively high 

compared to other states; thus, the state might be to avoid some of the problems 

associated with divestment of MSGD assets from primary to secondary firms that are 

predicted as gas production declines. Nonetheless, Maryland might want to consider 

alternate mechanisms of covering decommissioning and reclamation costs through a trust 

fund mechanism (i.e., investing revenue from pre-drilling fees and a five-year severance 

tax on production) as an alternative to performance bonding. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

1-27 

L. Literature cited 

Abbas, R., et al. 2003/2004. A safety net for controlling lost circulation. Oilfield Review 15:20-27. 

API. 2009. Environmental Protection for Onshore Oil and Gas Production Operations and Leases. API 

RP-51R. Washington, DC: American Petroleum Institute Publishing Services. 

Boyer, E. W., B. R. Swistock, J. Clark, M. Madden, and D. E. Rizzo. 2011. The Impact of Marcellus Gas 

Drilling on Rural Drinking Water Supplies. Harrisburg, PA: The Center for Rural Pennsylvania. 

Christopherson, S., and N. Rightor. 2011. The Boom-Bust Cycle of Shale Gas Extraction Economies. 

Ithaca, NY: CaRDI, Cornell University. 

Duigon, M. T., and M. J. Smigaj. 1985. First report on the hydrologic effects of underground coal mining 

in southern Garrett County, Maryland. Report of Investigations No. 41, U.S. Geological Survey. 

Elmore, A. J., J. P. Julian, S. M. Guinn, and M. C. Fitzpatrick. In review. Potential stream density in midAtlantic U.S. watersheds. Plos One. 

Fisher, K. 2010. Data confirm safety of well fracturing. The American Oil and Gas Reporter, July issue. 

Franz, R., and D. Slifer. 1976. Caves of Maryland. Educational Series No. 3, Maryland Geological 

Survey. 

Hammer, R. J. Van Briesen, and L. Levine. 2012. In fracking's wake: new rules are needed to protect our 

health and environment from contaminated wastewater. Natural Resources Defense Council. 

Hobba, Jr., W. A., D. W. Fisher, F. J. Pearson, Jr., and J. C. Chemerys. 1979. Hydrology and 

geochemistry of thermal springs in the Appalachians. Geological Survey Professional Paper 

1044-E, Washington, DC: U.S. Geological Survey. 

Klauda, R., A. Prochaska, and M. Kashiwagi. 2012. Recommended monitoring plan for surface waters 

associated with Marcellus shale gas development in western Maryland. Annapolis, MD (May 8, 

2012 Draft): Maryland Department of Natural Resources. 

Kostelnik, J., and K. M. Carter. 2009. Unraveling the stratigraphy of the Oriskany Sandstone: A necessity 

in assessing its site-specific carbon sequestration potential. Environmental Geosciences 16:187-

200. 

Lien, A. M., and W. J. Manner. 2010. The Marcellus shale: resources for stakeholders in the Upper 

Delaware watershed region. Pinchot Institute for Conservation. 

Marcellus Shale Advisory Commission. 2011. [Pennsylvania] Governor's Marcellus Shale Advisory 

Commission Report. 

Mitchell, A. L., and E. A. Casman. 2011. Economic incentives and regulatory framework for shale gas 

well site reclamation in Pennsylvania. Environmental Science and Technology 45: 9506-9514. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

Ohio Legislative Service Commission. 2010. Final analysis: Sub S.B. 165 (128th General Assembly). 

PADCNR. 2011. Guidelines for Administering Oil and Gas Activity on State Forest Lands. 

Commonwealth of Pennsylvania Department of Conservation and Natural Resources Bureau of 

Forestry. 

Sage Policy Group, Inc. 2012. The Potential Economic & Fiscal Impacts of Natural Gas Production on 

Western Maryland. Submitted on behalf of American Petroleum Council. 

Soeder, D. J., and W. M. Kappel. 2009. Water resources and natural gas production from the Marcellus 

shale. Fact Sheet 2009-3032, Baltimore, MD: U.S. Geological Survey. 

Staubitz, W. W., and J. R. Sobashinski. 1983. Hydrology of area 6, eastern coal province, Maryland, West 

Virginia, and Pennsylvania. Water-Resources Investigations Open-File Report 83-33, Towson, 

MD: U.S. Geological Survey. 

STRONGER. 2011. Colorado Hydraulic Fracturing State Review. Oklahoma City, OK: STRONGER, 

Inc. 

Trapp, Jr., H., and M. A. Horn. 1997. Delaware, Maryland, New Jersey, North Carolina, Pennsylvania, 

Virginia, and West Virginia. In Ground Water Atlas of the United States, by J. A. Miller, L2 - 

L24. Reston, VA: U.S. Geological Survey. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 1 

1-28 

Ubinger, J. W., J. J. Walliser, C. Hall, and R. Oltmanns. 2010. Developing the Marcellus Shale: 

Environmental Policy and Planning Recommendations for the Development of the Marcellus 

Shale Play in Pennsylvania. Harrisburg, PA: Pennsylvania Environmental Council. 

USDOE. 2011. Secretary of Energy Advisory Board Shale Gas Production Subcommittee Second Ninety 

Day Report. U.S. Department of Energy. 

USEIA. 2012. Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays. U.S. Energy 

Information Administration. 

USEPA. 2004. Evaluation of Impacts to Underground Sources of Drinking Water by Hydraulic 

Fracturing of Coalbed Methane Reservoirs Study. EPA 816-R-04-003. Washington, DC: U.S. 

Environmental Protection Agency, Office of Water. 

USEPA. 2011. Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources; 

EPA/600/R-11/122. Washington, DC: U.S. Environmental Protection Agency, Office of Research 

and Development. 

USEPA. 2012. Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources 

(Progress Report). EPA/601/R-12/011. Washington, DC: U.S. Environmental Protection Agency, 

Office of Research & Development. 

Zebrowski, M. J., J. R. Kelafant, and C. M. Boyer. 1991. Reservoir characterization and production 

potential of the coal seams in Northern and Central Appalachian basins. Proceedings of the 1991 

Coalbed Methane Symposium. University of Alabama Tuscaloosa. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

2-1

2. Protecting air quality1

Natural gas from MSGD has the potential to provide substantial energy economically and at a 

much lower cost to the atmospheric environment than the same amount of energy generated from 

coal combustion. In particular, natural gas (predominantly methane) has advantages over coal 

with respect to trapping of infrared radiation (IR) by greenhouse gases (GHGs) and contributing 

to planetary warming. The GHG advantage of natural gas arises from the relative heat (available 

for energy production) per unit of CO2 released in combustion. For each molecule of CO2

produced, roughly twice as much energy is available from natural gas than from coal. This 

advantage is only realized if the gas is combusted completely, however. In trapping IR radiation 

and warming the planet, methane is 30 times more potent than carbon dioxide (IPCC 2007). 

Therefore, if 1/30th (~3%) or more of natural gas is lost in production, processing, and transport 

to market, there is no climate advantage over coal2

. Actual emission rates are a hotly debated 

subject (Armendariz 2009, Howarth et al. 2011a, Howarth et al. 2011b, Cathles et al. 2012) and 

can only be estimated for local operations. Nonetheless, there is some evidence that emissions 

rates may be significantly higher than initial estimates (Petron et al. 2012). 

The specifics of the GHG calculation are as follows. Coal is roughly 80% carbon by mass; 

natural gas is about 90% methane. The combustion of a molecule of carbon or methane produces 

one molecule of CO2, but the methane produces roughly twice as much heat represented by the 

enthalpy of combustion, DH°. 

 

C + O2 → CO2 DH° = -94 kcal/mole 

CH4 + 2O2 → CO2 + 2H2O DH° = -193 kcal/mole 

The ratio depends on details such as the exact composition of coal and gas but can be 

approximated as 193/94 = 2.05 or ~ 2. Substantial amounts of methane are released in coal 

mining and processing as well. If natural gas is used as a substitute for coal in electricity 

generation, it offers the additional advantage of higher efficiency by approximately a factor of 

two. But the general rule holds: natural gas is better for climate than coal as long as losses can 

be kept below 3% of total production. 

Maryland’s primary air quality issues from among all of USEPA’s criteria pollutants are ozone 

(O3, also called photochemical smog or Los Angeles type smog) and fine particulate matter 

(PM2.5, the mass of particles less than 2.5 μm in diameter in a cubic meter of air). Maryland is in 

violation of the National Ambient Air Quality Standard (NAAQS: 75 parts per billion for an 8-hr 

average) for ozone and in or near compliance for PM2.5, although both standards are likely to be 

tightened in coming years. Maryland must also comply with the Regional Haze Rule to improve 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. (Appalachian Laboratory, University of Maryland Center for 

Environmental Science, Frostburg, MD 21532); Russell R. Dickerson, Ph.D. (Department of Atmospheric and 

Oceanic Science, University of Maryland, College Park, MD 20742) 2

 It should be noted, however, that natural gas has several other air quality benefits relative to coal, including lower 

emissions factors (lb/MMBTU) for nitrous oxides, sulfur dioxide, particulate matter, carbon monoxide, and 

mercury. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 2 

2-2 

visibility or visual range. The limit to visual range is generally fine particles, so comments on 

PM2.5 also apply to haze. Maryland is a member of the Regional Greenhouse Gas Initiative 

(RGGI) that seeks to limit emissions of pollutants that disrupt the Earth’s radiative balance 

including carbon dioxide, nitrous oxide, and methane. On a local scale, hazardous air pollutants 

(HAPs), malodorous gases such as hydrogen sulfide (H2S), and mercaptans (organic sulfur 

compounds) can be of concern, and radon (an α particle-emitting, respirable radioactive material 

produced as a decay product of radium present in the Marcellus shale formation)3

. 

In terms of emissions, Maryland’s top priorities are the precursors to O3 and PM2.5 (i.e., the 

chemical species that form these pollutants in the atmosphere). In the eastern U.S., both ozone 

and haze are considered to be secondary pollutants (made in the atmosphere by photochemical 

reactions of precursor gases) rather than primary pollutants (released directly into the 

atmosphere). Ozone forms by atmospheric reactions involving two main classes of precursor 

pollutants: volatile organic compounds (VOCs) and nitrous oxides (NOX); carbon monoxide 

(CO) is also important for O3 formation in polluted areas and in the remote troposphere. The 

formation of O3 from these precursors is a complex, nonlinear function of many factors 

including: (1) the intensity and spectral distribution of sunlight; (2) atmospheric mixing; (3) 

concentrations of precursors in the ambient air and the rates of chemical reactions of these 

precursors; and (4) processing on cloud and aerosol particles (USEPA 2012). Fine particular 

matter (PM2.5) are those particles (such as those found in smoke and haze) that can be deeply 

respired into the lungs; while the sources of these particles can be from forest fires, wood stoves, 

and other direct combustion sources (e.g., soot or “black carbon” emitted from the tailpipes of 

cars, trucks, and other on-road vehicles), they are commonly formed when gases emitted from 

power plants, industrial plants, and automobiles react in the atmosphere. The most common 

gases cited as precursors of PM2.5 formation include: sulfur dioxide (SO2), NOx, VOCs, and 

ammonia (NH3). Secondary formation of O3 and PM2.5 is thus linked by virtue of involving some 

of the same precursor pollutants. 

High quality (dry) natural gas is composed primarily of methane (CH4), but contains appreciable 

amounts (percentages) of other light alkanes such as ethane (C2H6), propane (C3H8), butane 

(C4H10) and pentane (C5H12). The amounts decrease with increasing carbon number, but recent 

evidence indicates wide variability among MSGD wells in neighboring states. Methane and the 

light alkanes themselves do not contribute significantly to ground level ozone or fine particulate 

matter. Heavier and unsaturated volatile organic compounds (VOCs), particularly biogenic 

isoprene, do contribute substantially to ozone formation, however. Hazardous air pollutants 

(HAPs) may also arise from natural gas production. Recently, evidence indicates that some 

natural gas operations could be non-negligible sources of benzene (C6H6), a variety of other 

HAPs, and heavier hydrocarbons (McKenzie et al. 2012, Petron et al. 2012, personal 

communication: R. Schnell, Global Monitoring Division, NOAA). These could pose a health risk 

to individuals living within ~1000 m of a gas operation. 

 

3

 Among different types of rocks, granites and rhyolites (igneous rocks) are most commonly enriched in uranium, 

but some sedimentary rocks—such as the Marcellus shale—that are rich in organic matter can be significantly 

enriched in uranium (and thus radium). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

2-3

The purpose of this chapter is to examine the sources of pollutants and air pollution precursors 

associated with MSGD operations and make recommendations of best management practices 

that should be use to control such emissions and protect air quality in Maryland locally, 

regionally, and globally. Ozone and PM2.5 are predominantly regional problems, as pollutant 

formation continues to occur well downwind of precursor emissions. Pollution events tend to 

have spatial scales of ~1000 km and temporal scales of 1-5 d. Releases of primary pollutants 

(particularly NOx) in western Maryland where MSGD could occur could certainly have adverse 

effects on eastern Maryland where NAAQS ozone violations occur. The regional scale of these 

problems would suggest that even if MSGD does not go forward in Maryland, the state’s air 

quality would be expected to be affected to some degree by activities in surrounding states; in 

particular, we are concerned that greater regional emissions of NOx into a regional atmosphere 

upwind (i.e., west) of Maryland would be expected to make it more difficult for the state to meet 

the NAAQS for ozone in the future. While no studies have been published on regional air quality 

impacts from MSGD, one numerical atmospheric modeling study of Texas and Louisiana 

indicated increases in the 8-hr ozone values of up to 5 ppb as a result of natural gas development 

of the Haynesville Shale (Kemball-Cook et al. 2010). 

A. Reducing pollutant and pollutant precursor emissions from MSGD operations 

Implementation of BMPs to control air pollution emissions in Maryland—as in neighboring 

Marcellus shale states—would be driven largely in an effort to comply with USEPA regulations 

under the Clean Air Act that mandate both New Source Performance Standards (NSPS) and 

National Emissions Standard for Hazardous Air Pollutants (NESHAP) for oil and natural gas 

production. In the following subsections we describe the BMPs that could be deployed to reduce 

emissions of the key air pollutants (and air pollution precursors) described above. 

Methane and VOCs. Determining BMPs for reducing methane and VOC emissions from MSGD 

is in part dependent on identifying and inventorying the specific sources of these gases within the 

gas sector. Again, no such studies have been conducted for the MSGD region, but a recent study 

of the Barnett shale region of Texas (Armendariz 2009) provides useful information that may be 

relevant to western Maryland. Emission sources in the gas industry can be classified as follows: 

(1) fugitive emissions; (2) vented emissions; and (3) combustion emissions. Fugitive emissions 

are unintentional leaks around seals and gaskets, leaks from underground pipelines due to from 

corrosion or faulty connections, or emissions that occur during the well completion process. 

Vented emissions are releases to the atmosphere by design or operational practice. Examples of 

vented emissions include: emissions from continuous process vents, such as dehydrator reboiler 

vents; maintenance practices, such as blowdowns; and small individual sources, such as gas 

operated pneumatic device vents. Combustion emissions are exhaust emissions from combustion 

sources such as compressor engines (Kirchgessner et al. 1997). Although there is quite a bit of 

uncertainty in methane emission rates both in absolute terms and expressed as a percentage of 

total production (Cathles et al. 2012), among the most significant emission sources of VOCs and 

methane are: (1) fugitive emissions during completion (Howarth et al. 2010); (2) fugitive 

emissions from compressor station and transmission systems (Kirchgessner et al. 1997, Howarth 

et al. 2010); and (3) routine venting emissions (Kirchgessner et al. 1997, Howarth et al. 2010). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 2 

2-4 

One best practice that can dramatically limit both VOC and methane emissions during the well 

completion phase is a procedure known as a “green completion” or “green flowback process” 

(Armendariz 2009). In this process, performed using special equipment brought onto the well 

pad, gases and liquids brought to the surface during the 3- to 10-day completion process are 

collected, filtered, and transported into production pipelines and tanks, instead of being dumped, 

vented to the atmosphere, or flared. After the completion process has ended, the produced gases 

and liquids can be directed to permanent on-site separators (that separate gas from water and any 

hydrocarbon liquids), condensate tanks, and piping that had been installed at the well site; 

condensate tanks are sources of emissions through venting to the atmosphere. “Green 

completions” are considered highly cost-effective in reducing VOC and methane emissions in 

the Barnett Shale in Texas (Armendariz 2009) and will be required by USEPA nationwide after 

January 1, 2015 under NSPS for VOCs and NESHAP for oil and natural gas production. 

Unfortunately, a major loophole in implementing green completions is that the process is not 

applicable to “exploratory” or “wildcat” drilling, because the well must be near an operational 

pipeline; therefore, such well completions have been exempted by USEPA from complying with 

this requirement. In a phased comprehensive gas development plan, Maryland could work with 

industry to site early pads at specific locations where “wildcatting” would be permitted; during 

this phase, green completions would not occur and gases would likely be flared during the 

completion process. Pending the outcome of this exploratory phase, construction of additional 

well pads and the associated pipeline and compressor infrastructure to transport gas would 

subsequently be coordinated in a second phase (during which green completions would be 

required). 

Two other final rules governing VOC and methane emissions were recently instituted by 

USEPA: (1) use of modified (“low bleed”) pneumatic controllers for many functions between the 

wellhead and the point where natural gas enters a transmission pipeline; and (2) use of new 

storage tanks for condensate which are capable of routing VOC emissions to a combustion or 

flaring device. Enclosed flaring devices are highly efficient (98%) devices that can dramatically 

reduce VOC and methane emissions from tanks (Armendariz 2009). USEPA is also trying to 

address VOC emissions for natural gas processing plants through the NSPS process—in 

particular controlling fugitive emissions from separators, glycol dehydrators, storage tanks, and 

metering stations. Many of these standards promote aggressive leak detection and repairs. Leak 

detection at processing plants is covered by NSPS and can be performed using handheld organic 

vapor meters (OVMs); inspections are performed at a specified frequency under the NSPS. 

Natural gas that is low in high molecular weight hydrocarbons may not require such processing, 

and we are not sure whether such plants will be required in Maryland. 

Expansion of a comparable leak detection and repair program that governs operations from 

wellhead to the transmission line would be considered a BMP for reducing emissions in 

Maryland and elsewhere, regardless of whether processing plants are necessary. Thermal 

imaging cameras (e.g., FLIR Commercial Systems B.V., Breda, The Netherlands) have been 

used to great effect in identifying hydrocarbon leaks in Houston refineries. These cameras can be 

mounted on aircraft to survey broad areas to identify major leaks of hydrocarbons; this approach 

might be applicable to identifying hydrocarbon leaks from well sites, compressor sites, and 

pipeline networks in the Marcellus region. The Texas Commission on Environmental Quality 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

2-5

(TCEQ) has identified leaks that, when repaired, saved the refinery operators substantial product 

loss that more than paid for the monitoring and repair actions.

4

 These and many other BMPs 

have been advocated by USEPA’s Natural Gas STAR program aimed at implementing costeffective strategies for reducing methane emissions by the industry5

; as proposed for New York 

State, best practice in Maryland would be that all operators voluntarily participate in this 

program and implement as many of the recommended strategies as possible (NYSDEC 2011), 

including: (1) reducing methane emissions from pneumatic devices in the natural gas industry; 

(2) reducing methane emissions from compressor rod packing systems; (3) reducing emissions 

when taking compressors off-line; (4) replacing glycol dehydrators with desiccant dehydrators; 

(5) replacing gas-assisted glycol pumps with electric pumps; (6) optimizing glycol circulation 

and installing flash tank separators in glycol dehydrators; (7) using efficient compressor engines; 

(8) using efficient line heaters; (9) using efficient glycol dehydrators; (10) re-using production 

brines; (11) ensuring all flow connections are tight and sealed; (12) performing leak detection 

surveys and taking corrective actions; (13) using efficient exterior lighting; and 14) using solarpowered telemetry devices. 

NOx. Unlike VOCs and methane that are principally emitted through fugitive and venting 

mechanisms, NOx is primarily a product of operating internal combustion engines. Large (1,000 

horsepower, HP) diesel internal combustion engines are often used to operate drilling rigs and 

power hydraulic fracturing pumps, although electric drill rigs can be powered off of the electrical 

grid where NOx is effectively capped at the electrical generating plant under the Clean Air Act 

Amendments. Smaller combustion engines are used to power compressors that produce and 

transport the gas through pipelines; these engines can be powered by either diesel fuel, natural 

gas, or electricity. An obvious best practice for controlling NOx emissions from MSGD in 

Maryland would be through the use of electrical drilling rigs, hydraulic fracturing pumps, and 

compressor engines that are operated off of line power; Maryland should consider mandating 

electrically-powered equipment wherever line power is available (or could be made readily 

available); this alternative might be reasonably cost-effective if MSGD can be conducted 

primarily or exclusively in densely clustered multi-well pad developments as discussed in 

Chapter 1. As an alternative to this practice that would be applicable to well pad locations not 

easily served by line power, Maryland could require that all engines (i.e., diesel and/or spark 

ignited for drilling devices, pumps, compressors, trucking, etc.) used by MSGD operators meet 

“fleet average” standards for NOx emissions based on USEPA 1998 standards for heavy-duty 

diesel highway vehicles of 4.0 g NOx/bhp-hr6

 equivalent to 25 g NOx/kg fuel7. In Texas, TCEQ 

has taken a similar approach in regulating NOx emissions in the Dallas-Fort Worth metropolitan 

area, although TCEQ used an even more stringent emissions standard of 0.5 g NOx/bhp-hr 

(Armendariz 2009). Operators would essentially have three options: (1) utilizing newer diesel 

engines that can meet these emission standards; (2) replacing internal combustion engines with 

electrically-powered motors; or (3) some combination of the two options that would expectedly 

be determined by cost. Either of these three options would have significant co-benefits in terms 

 

4

 See http://www.tceq.texas.gov/airquality/barnettshale/bshale-faq and 

http://www.texassharon.com/2012/03/20/tceq-videos-show-voc-emissions-in-eagle-ford-shale/ 5

 http://www.epa.gov/gasstar/tools/recommended.html 

6

 http://www.epa.gov/otaq/standards/heavy-duty/hdci-exhaust.htm. A bhp-hr is a brake horsepower-hour (a unit of 

work). 7

 This is similar to observed emissions rates for in-use vehicles, but not as stringent as the 2007+ standard of 0.2 g 

NOx/bhp-hr. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 2 

2-6 

of reducing VOCs as well, but engines (i.e., drilling devices, compressors, trucking etc.) could 

also be required to meet the “fleet average” of all engines set by the USEPA 1998 hydrocarbon 

(HC) standards for heavy-duty diesel highway vehicles of 1.3 g HC/bhp-hr8

. 

PM2.5. We recommend that Maryland require the “fleet average” of all internal combustion 

engines (i.e., drilling devices, compressors, pumps, trucking etc.) used in MSGD meet USEPA 

1998 standards for heavy-duty diesel highway vehicles of 0.1 g PM/bhp-hr9

. Restricting idling 

time and requiring use of ultra low sulfur diesel (ULSD) fuel would also be considered best 

practices. 

 

Hazardous air pollutants. Hazardous air pollutants (HAPs), particularly organic HAPs, have 

also been reported to exist in concentrations that are a cause for concern in the vicinity of natural 

gas production facilities and should be monitored near any Maryland sites. The compounds of 

primary concern as HAPs include benzene, toluene, ethylbenzene, and xylene (i.e., BTEX), as 

well as formaldehyde, among others. 

Radon. As discussed in Chapter 4, production brine is likely to contain elevated levels of 

naturally occurring radioactive material (NORM), principally radium-226 (226Ra)—a radon 

precursor. This material may pose a hazard to workers handling the drilling and recovery 

equipment, so gamma and alpha radiation from production brine should be monitored at each 

site. The radon gas itself that is released is unlikely to pose either a health or safety hazard unless 

it is contained in a confined space, however. There are no effective ways of controlling the 

release of radon to the atmosphere other than reburying the radium source. 

B. On-site and off-site air quality monitoring 

If and when drilling begins in Maryland, one way the state could attempt to address regional air 

quality issues (i.e., ozone) associated with developing the Marcellus shale would be to develop 

and implement an air emissions monitoring program throughout the region as has been proposed 

for Pennsylvania (Lien and Manner, 2010). The program would be focused on assessing both 

point sources and fugitive sources of pollutants (and pollutant precursors) at well pads and at 

other sources resulting from natural gas production. 

C. Key recommendations 

2-A Require that operators in Maryland establish a methane leak detection and repair program 

that governs operations from wellhead to the transmission line, regardless of whether 

processing plants are necessary. All operators in Maryland should voluntarily participate 

in USEPA’s Natural Gas STAR program aimed at implementing cost-effective strategies 

for reducing methane emissions by the industry. 

 

8

 http://www.epa.gov/otaq/standards/heavy-duty/hdci-exhaust.htm; this is not as stringent as the 2007+ standard of 

0.14 g HC/bhp-hr and is practicable with current technology at reasonable cost. 9

 http://www.epa.gov/otaq/standards/heavy-duty/hdci-exhaust.htm; this not as stringent as the 2007+ standard of 

0.01 g PM/bhp-hr and is practicable with current technology at reasonable cost. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

2-7

2-B Encourage operators to either use newer internal combustion engines or convert from 

diesel internal combustion engines to electric motors for operating drilling rigs, pumps, 

and compressors wherever possible by implementing “fleet average” emission standards 

for NOx, VOCs, and PM2.5. 

2-C Require monitoring of hazardous air pollutants at well pad sites. 

2-D Monitor gamma and alpha radiation of production brines. 

2-E Implement an air emissions monitoring program throughout the region, focusing on 

sources and fugitive sources of pollutants (and pollutant precursors) at well pads and at 

other sources resulting from natural gas production. 

D. Literature cited 

Armendariz, A. 2009. Emissions from natural gas production in the Barnett Shale area and opportunities 

for cost-effective improvements, report to EDF. 

Burgard, D. A., G. A. Bishop, and D. H. Stedman. 2006. Remote sensing of ammonia and sulfur dioxide 

from on-road light duty vehicles. Environmental Science & Technology 40:7018-7022. 

Cathles, L. M., L. Brown, M. Taam, and A. Hunter. 2012. A commentary on "The greenhouse-gas 

footprint of natural gas in shale formations" by RW Howarth, R. Santoro, and Anthony Ingraffea. 

Climatic Change 113:525-535. 

Howarth, R. W., A. Ingraffea, and T. Engelder. 2011a. Natural gas: should fracking stop?, Nature 

477:271-275. 

Howarth, R. W., R. Santoro, and A. Ingraffea. 2011b. Methane and the greenhouse-gas footprint of 

natural gas from shale formations. Climatic Change 106:679-690. 

IPCC. 2007. Intergovernmental Panel on Climate Change: Fourth Assessment Report, Geneva, 

Switzerland. 

Kemball-Cook, S., et al. 2010. Ozone impacts of natural gas development in the Haynesville shale. 

Environmental Science & Technology 44:9357-9363. 

Kirchgessner, D.A., R.A. Lott, R.M. Cowgill, M.R. Harrison, and T.M. Shires. 1997. Estimate of methane 

emissions from the natural gas industry. Chemosphere 35:1365-90. 

Lien, A. M., and W.J. Manner. 2010. The Marcellus shale: resources for stakeholders in the Upper 

Delaware watershed region. Pinchot Institute for Conservation. 

McKenzie, L. M., R. Z. Witter, L. S. Newman, and J. L. Adgate. 2012. Human health risk assessment of 

air emissions from development of unconventional natural gas resources. Science of the Total 

Environment, 424:79-87. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

Petron, G., et al. 2012. Hydrocarbon emissions characterization in the Colorado Front Range: a pilot 

study. Journal of Geophysical Research-Atmospheres 117. 

USEPA. 2012. Integrated Science Assessment for Ozone and Related Photochemical Oxidants (Third 

External Review Draft). EPA/600/R-10/076C. Research Triangle Park, NC: U.S. Environmental 

Protection Agency, Office of Research and Development 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-1 

3. Well engineering and construction practices to ensure integrity and 

isolation1

The primary goal of the oil and natural gas industry is to cost-effectively explore for and extract 

petroleum and natural gas from subsurface environments where such substances have formed 

and accumulated over geologic time—typically hundreds of millions of years. The most common 

approach to extracting these substances from onshore reservoirs is through the drilling of 

boreholes from the land surface to the target zone within which these substances are thought to 

be concentrated and then completing a well by hydraulic fracturing that provides a pathway for 

these substances to be brought to the surface in an efficient, safe, and controlled way. Obviously, 

well engineering and construction practices have evolved over time as operators have gained 

greater experience and as technological improvements have allowed. For a century or more in an 

era in which environmental resources were not greatly considered, the industry made very little, 

if any, significant effort to explore and produce oil and natural gas in ways that would be 

considered environmentally sound by modern standards. For example, large volumes of brine 

(saline water) that were brought to the surface with the oil and gas were typically stored in 

unlined pits that overflowed into streams and rivers or seeped into groundwater causing 

widespread water pollution. 

In recent decades, the industry has responded to pressure to reduce its environmental footprint 

and many best management practices (BMPs) have been developed and employed to ensure the 

integrity of each well system, isolate the well from the surrounding subsurface environment, and 

effectively contain the produced gas and other fluids within the well’s innermost production 

conduit so it can be successfully transported through ancillary pipelines for processing and 

delivery to market. Heightened environmental awareness and elevated environmental standards 

have also forced the industry to make substantial progress in collecting, storing, treating, and 

recycling of liquid drilling wastes (i.e., “flowback”, brines), although the industry still relies very 

heavily on underground injection as the ultimate disposal process. API—as the technical arm of 

the oil and gas industry—has taken the lead in reviewing and evaluating the industry’s practices 

for drilling, completing, and operating oil and natural gas wells; on the basis of its on-going 

technical reviews of various practices, API has published an extensive number of documents 

describing so-called “recommended practices” (RPs) which it communicates and shares with the 

industry. Many of these RP’s explicitly address problems in maintaining well integrity and 

provide standards that have been expressly adopted by some state regulatory authorities. 

Obviously, not all well construction activities go according to plan and—despite significant 

experience with hydraulic fracturing—there have been relatively few published data-driven 

studies that explicitly address the problem of transport of subsurface contaminants from 

hydraulically fractured horizontally-drilled gas wells into aquifers over the lifetime of a 

producing well (Myers 2012); the author of a white paper on the subject described the science of 

understanding this problem as “recent, ongoing, and incomplete” (Ingraffea 2012). The recent 

 

1

 Chapter author: Keith N. Eshleman, Ph.D. (Appalachian Laboratory, University of Maryland Center for 

Environmental Science, Frostburg, MD 21532) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-2 

modeling study by Myers (2012) addressed movement of contaminants to surficial aquifers 

through natural pathways—both advective transport through porous media overlying a 

hydraulically-fractured shale formation and preferential transport through fractures, but 

significant questions have been raised regarding the assumptions and conclusions of the study 

(Saiers and Barth 2012). Two recent peer-reviewed studies provided circumstantial experimental 

evidence that methane gas and formation brine can seep out of shale formations and contaminate 

overlying aquifers (Osborn et al. 2011, Warner et al. 2012), but the mechanism for such 

contamination is unknown and any relationship to hydraulic fracturing remains unproven 

(Osborn et al. 2011, Davies 2011). 

The Deepwater Horizon oil spill in the Gulf of Mexico in 2010 following the Macondo well 

blow-out is a chilling reminder of what can go wrong when well fluids cannot be isolated, 

contained, and controlled (in this example, due principally to a faulty cement job). The final 

report from the U.S. government’s official investigation into the causes of this accident also 

highlighted a series of decisions that complicated the cementing operation, increased the risks of 

failure, and were major contributing factors in the blow-out and explosion on April 20, 2010 that 

killed 11 men working on the drilling platform and caused the subsequent spill of an estimated 

4.9 million barrels of oil into the Gulf of Mexico (National Commission on the BP Deepwater 

Horizon Oil Spill and Offshore Drilling 2011). The Deepwater Horizon incident also underlines 

the importance of ensuring that the activities of all subcontractors working on a particular well 

are coordinated and adequately supervised by the lead operator (or prime contractor). 

The purpose of this chapter is to review and recommend best management practices for ensuring 

well integrity and isolation of unconventional Marcellus shale gas wells based on our review of 

API recommended practices and regulations in place in Colorado, Ohio, Pennsylvania, and West 

Virginia (and proposed regulations in New York State). Other best practices that are considered 

ancillary to well drilling, completion, and production (e.g., BMPs for containing, treating, and 

disposing of drilling wastes—especially “flowback” and brines) are discussed in Chapter 4. 

A. Well planning 

API provides a very detailed explanation of the critical need for operators to perform adequate 

well planning as a first step to ensuring well integrity and isolation (API 2010)2

. The rationale 

for such planning is very well established from experience, and optimum well planning for 

constructing wells for developing the Marcellus shale gas resource in Maryland would likely 

include the following elements: 

• evaluation of potential flow zones; 

• site selection; 

• hazard assessment and contingency planning; 

• well control planning for fluid influxes; 

• lost circulation control plans; 

• regulatory issues and communications plans; and 

 

2

 API Standard 65-Part 2 was prepared based principally on experience in the U.S. outer continental shelf and 

deepwater areas of the Gulf of Mexico, but the recommendations may be applicable to other offshore and onshore 

areas (see p. iii). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-3 

• construction designs and plans for a specific well that would include: (1) an analysis of 

pore pressures, fracture gradients, and required drilling fluid weights; (2) a casing plan; 

(3) a cementing plan; (4) a drilling plan; (5) a hydraulics plan that provides for adequate 

wellbore cleaning and control of static and dynamic wellbore pressures; (6) a barrier 

design that provides for control of all pressures that may be encountered during the life of 

the well; and (7) a contingency plan that addresses wellbore instability and unintended 

gains and losses of fluids. 

Site selection is a critical aspect of well planning, and we discuss some of the primary constraints 

on siting a well pad and wells in Chapter 1 (other environmental criteria are discussed in 

Chapters 5 through 10 of the report). We are particularly concerned about drilling in areas where 

there is a high probability of encountering large underground voids (e.g., caverns, caves, mine 

workings, abandoned wells, etc.) that have the potential to cause a loss of fluid circulation during 

drilling and impose additional risks during the cementing process. Such hazards are relatively 

common in western Maryland and we recommend that sites with a high probability of 

encountering such hazards be avoided. 

Another very important element of proper well planning includes appropriate regulatory review. 

Typically, the regulatory agency with jurisdiction for a particular well will need to review the 

well plan before operations can begin. All four states that we reviewed with active 

unconventional oil and gas development (Ohio, Pennsylvania, Colorado, and West Virginia) 

require some of the elements of the well plans recommended by API for offshore operations; in 

some cases, additional components are required. Pennsylvania’s and West Virginia’s 

requirements with respect to well planning are nearly identical, requiring information on3

• the anticipated depth and thickness of any producing formation, expected pressures, 

anticipated fresh groundwater zones and the method or information by which the depth 

of the deepest fresh groundwater was determined; 

• the diameter of the borehole; 

• casing type, whether the casing is new or used, depth, diameter, wall thickness and burst 

pressure rating; 

• cement type, yield, additives and estimated amount; 

• the estimated location of centralizers; 

• the proposed borehole conditioning procedures; and 

• alternate methods or materials as required by the state regulatory agency as a condition 

for the well permit. 

 

Both states’ well planning requirements lack any explicit attention to potential flow pathways 

that are addressed in Ohio’s oil and gas regulations, however. Agency review of a well permit 

application in Ohio includes a review of wells and other potential pathways for contamination of 

groundwater within the minimum spacing distance for a proposed well (with the review 

extending along the entire lateral of a horizontal well and includes plugging records for plugged 

wells and casing records for other offset wells)4. Ohio also requires that applicants meet 

 

3

 25 Pa Code § 78.83a. Casing and Cementing Plan (provisions were adopted February 4, 2011, effective February 

5, 2011, 41 Pa.B. 805). 4

 Ohio Administrative Code 1501:9-1-08 Well construction. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-4 

additional requirements when planning to drill in urban areas such as (1) photo imagery and 

location information for tanks and flow lines, and (2) notification of all property owners within a 

500 ft radius around the proposed well. Ohio also requires a pre-permit on-site review in 

cooperation with local officials or their designees in urban areas. In general, we found that the 

state requirements for well planning lack many of the essential elements recommended by API 

such as: hazards assessment and contingency planning, plans for addressing lost circulation, and 

hydraulics plans for controlling all static and dynamic borehole pressures. API (2009a) also 

recommends that operators investigate and review the history of nearby wells for cementing 

problems encountered (e.g., lost returns, irregular hole erosion, poor hole cleaning, poor cement 

displacement, etc.) prior to drilling; computer simulation and other planning should be carried 

out to optimize casing and cement placement procedures. A BMP for anyone proposing to 

operate in Maryland should be adoption of API’s extensive guidelines for well planning—at least 

those elements that are clearly relevant to onshore development. API may choose to eventually 

develop BMPs for well planning that are specific to onshore operations, but until such practices 

can be determined, the adoption of the practices advocated in API Standard 65—Part 2 (API 

2010) would at least ensure that a prospective operator has addressed in writing all of the major 

hazards likely to be encountered and effectively communicated these, and contingencies for 

addressing them, to all subcontractors and to the appropriate regulatory authorities prior to 

spudding the well. Ohio’s requirement for pre-permit on-site review by state regulatory staff 

should also be adopted by Maryland, but this requirement should be expanded to all proposed 

gas wells (not just those proposed for urban areas). 

B. Drilling 

Constructing a Marcellus shale gas well typically requires several cycles of drilling, installing of 

casing strings, and cementing casing strings in place to ensure integrity and isolation. During 

each cycle, lengths of steel casing are installed in sequentially smaller diameters inside a 

previously installed and cemented casing string. Drilling the well utilizes a drill string, consisting 

of a drill bit, drill collars (heavy weight pipe to put weight on the bit), and sections of drill pipe. 

The drill string is assembled and run into the hole, and suspended at the surface from a drilling 

derrick or mast. The drill string is then rotated by the use of a turntable (rotary table), top drive 

unit, or downhole motor drive. During drilling, a fluid is normally circulated down the drill string 

and up the space between the drill string and the hole that: (1) provides lubrication of the drill 

bit; (2) removes the formation cuttings; (3) maintains control of pressures in the well; and (4) 

stabilizes the hole being drilled. Drilling fluid is generally a mixture of water, clays, fluid loss 

control additives, density control additives, and viscosifiers. Drilling fluid is a carefully 

monitored and controlled mixture designed to achieve best drilling results (API 2009a). 

The first hole to be drilled is a conductor pipe. In some cases the conductor pipe can be driven 

into place like a structural piling, but in western Maryland any conductor hole would need to be 

drilled. A conductor hole would logically be drilled to a depth that would provide isolation from 

any nearby water wells or freshwater springs. The conductor hole would be followed by 

sequentially deeper (smaller diameter) holes drilled to install the surface casing, the intermediate 

casing (if necessary), and the production casing (API 2009a). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-5 

Prior to drilling, best practice would be to either slightly crown the location around the wellbore 

to divert fluids to a flow ditch, or construct a liquid-tight cellar at least three ft in diameter to 

prevent surface infiltration of fluids adjacent to the wellbore. A Marcellus shale gas well would 

typically begin by drilling vertically through the subsurface zone containing freshwater aquifers 

(both unconfined and confined) that can provide groundwater (or USDW5); in many areas, coal 

seams will also be encountered while drilling for the surface casing. Caution must be taken while 

drilling through this zone to adequately protect USDW from contamination, and state regulations 

are meant to require operators to prudently drill through fresh groundwater zones so as to 

minimize disturbances to such zones6

. One way that this can be accomplished is by drilling all 

intervals prior to reaching a “USDW protective depth” either on compressed air, fresh water, a 

freshwater-based drilling fluid, or a combination of the above. Ohio, for example, requires that 

only additives that are suitable for drilling through potable water supplies may be used while 

drilling these intervals, although the Chief of the Department of Mineral Resources Management 

(DMRM) has the authority to require the use of a freshwater-based drilling fluid and specify its 

characteristics while an operator is 

drilling any interval prior to reaching 

the USDW protective depth.7

Maryland explicitly prohibits the use 

of any additives to drilling liquids 

without approval of MDE (except 

under emergency conditions), and 

this regulation should be retained. 

An intermediate hole (if needed) is 

also drilled vertically after the 

surface casing has been set and 

properly cemented—in some cases 

to a kick-off point that would allow a 

downhole motor to gradually make 

the turn from vertical to a 

predominantly horizontal direction 

during drilling of the production hole 

(Figure 3-1). An intermediate casing 

is typically used to isolate the well 

from any subsurface formations 

below the protective USDW depth that could cause well instability and provide protection from 

any abnormally pressurized subsurface zones (API 2009a). The intermediate hole would not 

likely be drilled “on air”. Downhole motors (which operate using the hydraulic pressure exerted 

by the drilling fluid) are “steerable,” meaning that the direction (in all dimensions) of drilling can 

be controlled from the surface to stay within the target formation (API 2009a). New York State 

has recommended that both the intermediate and production wellbores can be drilled after all 

freshwater aquifers have been properly sealed behind steel casing and cement (see Section C) 

 

5

 A USDW is defined by federal statute (40 CFR 144.3). The term “groundwater” is more general and includes 

subsurface waters that do not necessarily meet the legal definition of USDW. 6

 e.g., §22-6A-24 (West Virginia Horizontal Well Act, H.B. 401) 

7

 Ibid., 4 

Figure 3-1: Horizontal drilling technology requires the ability to make 

a turn from vertical to horizontal drilling at depths ranging from 2,000 

to 9,000 ft below the surface. These flexible drilling pipes are used to 

accomplish this task.
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-6 

with a mud that may be either: (a) water-based; (b) potassium chloride/polymer-based with a 

mineral oil lubricant; or (c) synthetic oil-based. Synthetic oil-based muds are described as 

“food-grade” or “environmentally friendly.” When drilling horizontally, mud is needed to: (a) 

power and cool the downhole motor and bit used for directional drilling; (b) operate the 

navigational tools which require mud to transmit sensor readings; (c) provide stability to the 

horizontal borehole; and (d) efficiently remove cuttings from the horizontal hole. Some operators 

can apparently drill the horizontal wellbore “on air” (i.e., with compressed air) using special 

equipment to control fluids and gases that enter the wellbore (NYSDEC 2011). 

Air drilling has now been used extensively in the Appalachian region for both gas drilling and 

for drilling water wells and should probably be considered a best practice. Air drilling is a 

process that utilizes high pressure air rather than water as the fluid to remove the rock fragments 

and cool the drill bit when drilling through rock. Its principal environmental benefit is that less 

water is utilized during the drilling process and dry rock fragments are returned to the surface 

rather than a slurry of water, drilling mud, and rock fragments. Air drilling also reduces 

wastewater generation and subsequent treatment (Lien and Manner 2010), but it cannot always 

be done safely—especially under conditions in which excessive subsurface pressures and flows 

may be encountered that cannot be effectively be controlled without the use of a drilling liquid. 

In addition to cooling and cleaning the drill bit and bringing cuttings to the surface, the use of 

drilling mud serves another important purpose: the density (i.e., weight of the fluid volume) of 

the mud effectively controls the formation pressures; well pressures can be held in check as long 

as the mud weight is sufficient to prevent flows from the formations being drilled. As higher 

pressures are encountered in deeper formations, it is therefore necessary to increase the mud 

density to offset those pressures (King 2012). 

Maryland’s current oil and gas regulations state that “drilling liquid may be required when there 

is insufficient geological data to safely drill with air as the circulating medium”8

. Maryland also 

requires that when drilling on air is permitting, sufficient liquid shall be available on-site to kill 

any unexpected flow from a particular well9. Maryland should consider the experiences gained 

by other states and permit air drilling of any holes (i.e., the conductor hole and surface hole) 

above the USDW protective depth [which API (2010) considers to be 100 ft below the deepest 

USDW encountered while drilling10), although the current regulations should be retained so that 

air drilling can be permitted on a case-by-case basis.11 If and until the freshwater/saline water 

interface is mapped in Maryland, the state will have to rely on operators to determine when the 

USDW protective depth has been reached while drilling the surface hole (likely on the basis of 

data obtained from geophysical logs from a particular borehole). Casing setting depths should be 

 

8

 COMAR 26.19.01.10.F 

9

 COMAR 26.19.01.10.I 

10 Maryland’s current oil and gas regulations require that a string of surface casing be installed in a hole which is at 

least 100 ft below the deepest known stratum bearing freshwater or the deepest known workable coal bed, 

whichever is deeper (COMAR 26.19.01.10.O(4)). 11 On the other hand, it is important to case and cement any surface hole prior to drilling into hydrocarbon-bearing 

flow zones or zones which contain waters with TDS concentrations exceeding 10,000 mg/L to avoid 

contamination of USDW as recommended in Ohio’s regulations. For this reason, in areas where USDW cannot be 

adequately mapped, Ohio’s oil and gas regulations also allow for use of a conductor casing through the deepest 

useable water zone that is first cemented to the surface, followed by setting and cementing of a surface casing 

string through water zones that may include brackish or brine bearing zones. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-7 

specified in the drilling plan, but the actual lengths of these strings can be adjusted based on field 

measurements and data collected during the drilling operation (API 2009a). 

We recommend Maryland develop regulations on wellbore diameter to ensure adequate spacing 

for equipment and instrumentation that will need to be run into the wellbore and for an adequate 

thickness of cement (i.e., a “sheath”) inside the annular space. Ohio has some excellent 

regulations that require that the diameter of each section of the wellbore in which casing will be 

set and cemented to be at least one inch greater than the outside diameter of casing collar to be 

installed, unless otherwise approved12. Ohio also requires that any wellbore diameter shall be 

consistent with manufacturer's recommendations for all float equipment, centralizers, packers, 

cement baskets, and any other equipment that will need to be run into the wellbore13. 

C. Casing and cementing 

Casing and cementing are critical elements of any well construction that must be properly 

designed and engineered to ultimately serve their primary purpose of providing well integrity 

and isolation from surrounding subsurface formations while providing a pathway by which the 

gas can be safely extracted over the life of the well. For this reason, both API and all five states 

that we reviewed have very lengthy descriptions of practices and standards that should govern 

these important well construction tasks. The steel casing must be capable of withstanding all the 

forces that are exerted on it while running it into a hole, as well as during subsequent cementing 

and hydraulic fracturing operations. Similarly, cementing is used to provide isolation of 

subsurface flow zones, provide structural support of the well, and protect the casing from 

corrosion. The cement must also be able to contain all pressurized fluids during all phases of 

drilling and operation of the well. Operators (including company engineers who design the well 

casings, their supervisors, and any drilling subcontractors involved in casing installation and 

cementing) bear the primary responsibility for ensuring that these critical tasks are carried out 

properly. Therefore, as noted in Section A, a critical element of a properly-executed well 

construction plan is a “casing and cementing plan” that is required by all five states that we 

examined. In many cases, state regulations require that standards (e.g., compressive strength of 

the cement) must be consistent with those recommended by API. 

Without detailed geological characterization (“cross-sections”) of the subsurface strata in 

western Maryland (including depths that various formations will likely be encountered, depths of 

the USDW/saltwater interface, etc.), it is very difficult to make anything but general 

recommendations for setting and cementing casing strings in place. Based on anticipated depths 

to the target formation, we believe it is likely that Marcellus shale gas wells in Maryland will 

normally require four casing strings (i.e., conductor casing, surface casing, intermediate casing, 

and production casing). All steel casing used in a Marcellus shale gas well should be 

manufactured to API specifications and meet strict requirements for compression, tension, 

collapse, and burst resistance, quality, and consistency (including API Spec 5CT); casing should 

also be designed to withstand all anticipated hydraulic fracturing pressures, production pressures, 

and corrosive conditions expected to be encountered. Used or reconditioned casing would only 

be used if it is shown to meet API standards for new casing (API 2009a). Casing and coupling 

 

12 Ibid. 

13 Ibid. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-8 

threads should also meet API standards, and casing strings should be assembled to the correct 

torque specifications to ensure leak-proof connections. Casing centralizers should be used to 

properly center the casing in the hole and provide for good mud removal and cement placement 

in the form of a continuous sheath around the casing string. API lists recommended types of 

centralizers and has various formulae for determining the type, number, and best placement of 

centralizers along a particular casing string (API 2009a). Maryland should require that operators 

use casing that meets the high standards recommended by API, as well as a sufficient number of 

centralizers to properly center the casing in each borehole. 

API also provides good recommendations of materials and practices for ensuring that the various 

casing strings are properly cemented in place and can provide the desired zonal isolation of 

different formations, including complete isolation of USDW. Best practices are for an operator to 

(a) provide notice to the appropriate regulatory agency at least 24 hours prior to the 

commencement of any cementing operations; and (b) maintain a copy of the cementing records 

at the well site during the drilling and completion of the well. Cementing is best achieved by 

pumping a cement mixture (or “slurry”) down inside the casing string being cemented and 

circulating the cement mixture back up the outside of the casing (i.e., between concentric rings of 

casing or between the outermost casing and the borehole wall). Top and bottom wiper plugs are 

used to minimize mixing of the cement with drilling fluids inside the casing while the cement is 

being pumped. Zonal isolation and integrity of the well to minimize migration of fluids through 

the annulus are highly contingent on complete displacement of the drilling fluid by the cement 

mixture; complete and tight filling of the annulus with the cement mixture to the proper height 

above the bottom of the hole; absence of voids; and good bonding with the casing strings and 

borehole walls (API 2009a). Appropriate testing of cement should always be carried out by the 

service company to ensure that the mixture meets the criteria specified for the specific 

application. It is recommended that all surface casings be cemented with a continuous column 

from the bottom of the casing to the surface. 

Most of the states that we reviewed have established recommended standards and minimum 

compressive strength values for cement used in oil and gas wells, and describe how tests of 

cement should be conducted (i.e., API RP 10 B-2 “Recommended Practice for Testing Well 

Cements”). As in most states, New York has proposed cementing the surface casing by the 

pump and plug method with circulation to the surface, with a minimum of 25% excess cement 

pumped, with appropriate lost circulation materials; testing of the mixing water for pH and 

temperature prior to mixing; cement slurry preparation to the manufacturer’s or contractor’s 

specifications to minimize free water in the cement; and no casing disturbance after cementing 

until the cement achieves a calculated compressive strength of 500 pounds per square inch (psi) 

(NYSDEC 2011). Similarly, in Ohio, cemented casing strings shall remain static until all cement 

has reached a compressive strength of at least 500 psi before drilling the plug, or initiating any 

integrity testing14. 

While cementing of both the conductor and surface casing strings should normally be completed 

from top to bottom, there are likely to be situations in which large underground voids are 

encountered during drilling that preclude circulation of cement back to the surface. Under these 

circumstances, it may be possible to perform a cementing operation from top to bottom (i.e., a 

 

14 Ibid., 4 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-9 

“top job”) on a conductor casing, but this approach is normally not recommended because of 

difficulties in isolating the various water-bearing formations and thus protecting USDW as 

discussed in Chapter 1. In one of its publications, API notes that “a top job should be done only 

as a last resort” (API 2010). If it is determined that a “top job” will be necessary, then the 

conductor casing should be installed as deeply as possible to protect all USDW, and it should be 

absolutely required that the surface casing be fully cemented from bottom to top. 

API (2009) recommends that cementing of intermediate casing should also be done in the normal 

manner (i.e., bottom to the surface), but notes that there may be situations where this technique is 

unnecessary (e.g., where the surface casing string is fully protecting the USDW) or is inadvisable 

(e.g., where attempts to do so result in lost circulation of the slurry). According to King (2012), 

in cases of very long intermediate casing strings, cementing the full casing string may be illadvised due to the risks of fracturing formations by the pressure exerted from the weight of a 

column of cement (nearly twice the weight of an equivalent column of water). On the other hand, 

cementing an intermediate string to an insufficient height may leave the annulus exposed to 

higher pressures from non-isolated gas-containing shales and coals that could provide a pathway 

for migration of gas into the outer annulus and into overlying freshwater zones (King 2012). 

While we were able to find relatively few published studies that explicitly address the problem of 

freshwater contamination resulting from overpressurization and flow through the annulus, there 

is one older study that addressed this problem using a modeling approach (Harrison 1985). A 

more recent paper hypothesizes that high methane concentrations in drinking water aquifers in 

Pennsylvania are most likely attributed to annular overpressurization resulting from leaky well 

casings rather than from hydraulic fracturing (Osborn et al. 2011), although other mechanisms 

are at least as plausible (Davies 2011, Jackson et al. 2011). Data from Warner et al. (2012) may 

also be consistent with the same mechanism whereby Marcellus Formation brine has seeped into 

shallow aquifers in Pennsylvania. We cannot make a clear recommendation with respect to 

installing and cementing intermediate casing strings; this is a situation where the best design and 

construction practices will be determined, in part, by the specific geological conditions that are 

encountered while drilling in western Maryland. At a minimum, however, an absolute 

requirement should be that all flow zones (including USDW) must be fully protected through the 

use of cemented intermediate well casings. Where this cannot likely be accomplished with a 

single casing string, the use of multiple strings should be favored in the well design (even if this 

results in greater costs in casing and cementing). 

Problems encountered in cementing of gas well casings have significant implications for upward 

contaminant migration into USDW; a recent white paper provides a description of several 

mechanisms by which oil and gas wells develop fluid leaks and lose their structural integrity 

(Ingraffea, 2012): (1) repeated pressurization of casings with open-annulus sections; or (2) high 

gas pressures encountering curing cement or entering open-annulus sections. Related to these 

problems, loss of integrity due to poor cementing can also be attributed to: (1) poor cement 

placement (i.e., failure to displace the mud prior to cementing or failure to generate a sufficient 

height of cement within the annulus to fully cover flow zones); (2) lack of centralization of the 

casing string; and (3) from gas migration through the cement as it sets in place (King 2012). In 

particular, the latter problem has apparently been known for decades, but many operators are 

unaware of the hazards that gases create if they are allowed to migrate sufficiently up a setting 

cement column, establishing a network of linked subchannels. Mud channels formed in setting 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-10 

cement can allow for gas or fluid migration through the annulus if these voids are continuous. 

Fortunately, large voids or channels are not typically continuous over long distances, but microannulus (hairline) cracks that allow for such migration must be detected through well logging 

(see Section D) and addressed accordingly (King 2012). 

D. Well logging 

Useful geophysical data to support MSGD in Maryland would likely be obtained from a variety 

of sources, particularly: (1) published geological maps of the region from USGS or private 

sources; (2) available well log records from previous gas and water well drilling in Maryland and 

surrounding states; (3) results from seismic refraction tests conducted as part of exploration 

activities; and (4) results from test (“pilot hole”) drilling (the latter providing information for 

improving stratigraphic interpretation specifically through calibration of seismic data). Data from 

these sources would likely be sufficient to: (1) identify subsurface drilling hazards; (2) accurately 

assess the location of the target zone; and (3) enable the design of production wells and detailed 

well plans. Once drilling for production actually begins, there are many types of data that would 

be collected through well logging techniques to provide detailed records of subsurface properties 

actually encountered in the well construction process. 

Open-hole logging is a method used in borehole geophysics that is conducted after drilling the 

hole, but before any casing is installed. Open-hole logging can provide important information on 

the specific depths of various formations encountered during the drilling process—and is thus 

very important in optimizing the well design and drilling operations. Drilling each hole to the 

correct depth theoretically allows casing strings to be installed at optimal locations to achieve 

maximum well integrity (API 2009a). Logging while drilling (LWD) technology was initially 

developed in the 1970s, but the technology now allows for most “open-hole” measurements to be 

made without lowering a suite of instruments into the borehole as part of a “wireline”. With 

either LWD or traditional wireline technology, it is possible to accurately determine formation 

properties from gamma ray logs (lithology), electrical resistivity logs (hydrocarbons), neutron 

porosity logs (liquid-filled porosity), and density logs (bulk density)—among others; borehole 

caliper logs provide measurements of the size (i.e., diameter) and shape of the borehole along its 

length that are crucial in estimating cement volumes. Mud logging is another borehole 

geophysical technique which is most commonly used in the petroleum industry to determine the 

concentration of natural gas being brought to the surface with the drilling mud. Modern 

measurement while drilling (MWD) technology allows information on natural gas levels to be 

obtained near the drill bit, thus providing an additional level of safety for rig workers in the event 

that levels are observed to reach dangerous levels. It is likely that all of these types of well 

logging would be used in MSGD in western Maryland. 

Other types of well logging occur after cementing the casing, including gamma ray logging and 

cement bond logging (CBL). The objectives of a cased-hole logging program are to determine 

the exact location of the casing, the casing collars, and the integrity of the cement job (especially 

as a function of location relative to various subsurface formations). CBL is an acoustic technique 

that works by transmitting a vibration and then recording the amplitude of the arrival signal at a 

detector. Casing that is not encased in cement produces a relatively high amplitude acoustic 

signal because the sonic energy is not very well absorbed. Conversely, casing with a good sheath 

of cement throughout the annular space produces a much smaller amplitude signal because the 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-11 

sonic energy would be much better absorbed. A variable density log (VDL) provides a graphical 

representation of the receiver waveform (API 2009a). Finally, newer equipment used by bond 

logging service companies apparently has the capacity to do segmented radial cement bond 

logging (SRCBL)—a technique for determining the presence and location of “mud channels” in 

the cement that would be indicative of poor zonal isolation. Such channels, if extensive or 

continuous, could provide a pathway for unintended gas or liquid flow within the annulus (King, 

2012). An SRCBL can be combined with equipment for gamma ray logging, casing collar 

logging, and neutron logging during a single descent.15 Additional information on the various 

types of cement evaluation tools that are available can be found in API TR 10TR1. 

We found relatively little agreement among the states as to which well logging techniques 

constitute best practice. Apparently neither Pennsylvania nor Ohio require any well logging 

(either open-hole or cased-hole), while West Virginia requires only a CBL. Colorado requires 

that operators run a minimum of a: (1) resistivity log with gamma-ray or other approved 

petrophysical logs that adequately describe the stratigraphy of the wellbore; and (2) a CBL on all 

production casing or, if a production liner is used, on the intermediate casing. Colorado also 

requires that open hole logs shall be run at depths that adequately verify the setting depth of 

surface casing and any aquifer coverage and that all logs run shall be submitted with a well 

completion or recompletion report to the regulatory authority. New York State has proposed that 

a radial cement bond evaluation log or other approved method should be use to verify the cement 

bond on the intermediate casing and the production casing (NYSDEC 2011). The best practice 

would utilize modern open-hole well logging methods to help fine tune casing placement and 

characterize flow and hydrocarbon zones, perhaps mud logging to determine levels of 

hydrocarbons in real-time during drilling, and SRCBL, casing collar logging, and gamma 

logging as part of a cased-hole program. We found virtually no information on possible remedial 

actions that can be taken by an operator in the event that problems with cement bond integrity 

are identified through the logging process. If remedial actions cannot fully resolve cement bond 

integrity issues, the operator should have no recourse but to correctly plug and abandon the well 

in accordance with state regulations. 

Maryland’s current regulations16 apparently require only electrical induction and gamma ray 

“open-hole” logging to determine the depth of freshwater, but they also require operators to 

maintain a detailed driller’s log book17 and provide MDE with a completion report within 30 

days after drilling, stimulating, and well testing have been completed18. Such completion reports 

include, among other items, information on the lithology of the penetrated strata, generalized 

core descriptions, estimates of porosity and permeability of formations, and copies of all logs run 

of the well. Maryland should consider amending its regulations to require SRCBL (or equivalent 

casing integrity testing) and other types of logging (e.g., neutron logging) to assist with 

determining the depth of freshwater as part of a cased-hole program. 

 

15 e.g., Tetra Technologies (2012); http://tetratec.com/index.asp?page_ID=309 16 COMAR 26.19.01.10.O(3) 

17 COMAR 26.19.01.10.R 

18 COMAR 26.19.01.10.V 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-12 

E. Pressure testing 

API (API 2009a) and the five states that we reviewed all call for testing of the various casing 

strings after the cement has achieved the appropriate compressive strength during a pre-specified 

wait-on-cement (WOC) period, but prior to drilling out. These tests are known as casing pressure 

tests and are performed to ensure that the integrity of each casing string is adequate to meet the 

well design and construction objectives. Recommended pressures and holding times for these 

tests were not consistent among the states, and API (2009) does not provide specific 

recommendations. In West Virginia, for example, the regulations only state that an operator 

should conduct the test at a pressure more than 20% greater than the pressure expected to be 

exerted on the casing. Similarly, in Pennsylvania, to pass a casing pressure test, the casing must 

hold the anticipated maximum pressure to which the casing will be exposed for 30 minutes with 

not more than a 10% decrease; certification of the pressure test shall be confirmed by entry and 

signature of the person performing the test on the driller’s log. API also recommends that 

formation integrity tests (also known as “shoe tests” or “leak-off tests”) be performed after 

drilling out both the surface and intermediate casings (API 2009a). Best practice would clearly 

call for use of pressure testing of Marcellus shale gas wells in Maryland, with specific criteria 

and technical details governing the conduct of such tests likely established through consultation 

with industry. Maryland’s current regulations19 with regard to pressure testing of cemented 

casings are even less specific than those established by neighboring states and appear to be in 

need of revision. 

F. Blow-out prevention 

Blow-out prevention equipment (BOPE) on a rotary drilling rig is a pressure control system 

installed at the top of the surface casing that is designed specifically to contain and control a 

“kick” (i.e., an unexpected pressure resulting in the flow of formation fluids into the wellbore 

during drilling operations). BOPE consists of four parts: 1) a blow-out preventer stack, 2) an 

accumulator unit, 3) a choke manifold, and 4) a kill line. Blow-out preventers are manually or 

hydraulically operated devices. Within the blow-out preventer there may be a combination of 

different types of devices to seal off the well. A suitable BOPE should have at least two 

redundant (and operational) mechanisms for preventing a blow-out. Pipe rams contain two metal 

blocks with semi-circular notches that fit together around the outside of the drill pipe when it is 

in the hole to block movement of fluids around the pipe. Blind rams contain two rubber faced 

metal blocks that can completely seal off the hole when there is no drill pipe in it. Annular or 

"bag" type blowout preventers contain a resilient packing element which expands inward to seal 

off the hole with or without drill pipe. To be effective, BOPE systems must be maintained and in 

proper working order during operations; a BOPE testing program must be employed on a regular 

basis to ensure that the system is functioning properly if and when it is needed (NYSDEC 2011). 

All BOPE should have a working pressure rating that exceeds the maximum expected surface 

pressure; training exercises or drills should be held as necessary to ensure crew familiarity and 

that the BOPE is in good working order (API 2009a). 

BOPE is an example of a temporary mechanical barrier for preventing loss of well control 

through annular flows (API 2010). It should be kept in mind that BOPE is not the only type of 

barrier used during drilling and completion. Columns of fluids (e.g., drilling fluids, cement 

 

19 COMAR 26.19.01.10.S(3)
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-13 

slurries, fracturing fluids, etc.) are considered hydrostatic barriers, because they can provide 

hydrostatic pressure that exceeds the pore pressures of potential flow zone, thus maintaining 

control of flow in the annulus. Set cement is usually the ultimate barrier element, but its 

competency should be carefully assessed prior to removing a mechanical barrier such as BOPE. 

There are many other types of mechanical barriers that are used by the oil and gas industry, but 

we lack the technical capacity to make recommendations as to which specific types of barriers 

would be employed in developing Maryland’s Marcellus shale gas resource. 

Pennsylvania requires the use of BOPE for drilling production wells for natural gas in 

unconventional formations20, but Ohio and West Virginia do not. In Colorado, the use of BOPE 

is required only when drilling in high density areas; otherwise it is at the discretion of the 

regulatory agency (COGCC). In Colorado, pressure testing of the casing string and each 

component of the blowout prevention equipment (if blowout prevention equipment is required) 

should be conducted prior to drilling out any string of casing except the conductor pipe. The 

minimum test pressure should be 500 psi, and that pressure should hold for 15 minutes without 

pressure loss in order for the casing string to be considered serviceable. Use of BOPE with two 

or more redundant mechanisms should be considered a best practice for MSGD in Maryland. 

G. Completing and hydraulic fracturing 

The production casing is normally run to the total depth of the well and—once cemented—is 

intended to provide: (a) total zonal isolation between the production formation and all other 

subsurface formations; (b) a continuous conduit to the surface for pumping hydraulic fracturing 

fluids into the production formation without affecting other subsurface formations; (c) a 

continuous conduit for containing and transporting hydrocarbons between the production zone 

and the surface; and (d) a secondary barrier for the production tubing and packer that are used in 

the final completion step (API 2009a). In the absence of using an intermediate string, New York 

State recommends cementing of the production casing all the way to the surface (NYSDEC, 

2011). Similarly, in Ohio, when cementing the production string of a well that will be stimulated 

by hydraulic fracturing, and the uppermost perforation is less than 500 ft below the base of the 

deepest USDW, sufficient cement shall be used to fill the annular space outside the casing from 

the seat to the surface. Since we explicitly recommended against drilling in situations where 

there is less than 1,000 vertical ft between USDW and the production formation, this option 

should not apply in western Maryland. Recommendations by API and used by the state of Ohio 

both call for cementing of the production casing to a depth at least 500 ft above the highest 

formation in which hydraulic fracturing will be performed, however. Ohio calls for use of a 

cement slurry that is designed to control annular gas migration consistent with recommended 

methods in API (2010). However, both API (2009a) and Ohio regulations allow for “open-hole” 

completions and the use of production liners in some circumstances. Maryland regulators will 

have to work with industry to carefully evaluate the pros and cons of these different completion 

options. 

Hydraulic fracturing (sometimes referred to as “fracking”) is a well stimulation technique 

employed by the oil and gas industry to increase the permeability of a hydrocarbon-bearing 

 

20 25 Pa Code § 78.72. Use of safety devices—blow-out prevention equipment (provisions adopted July 28, 1989, 

effective July 29, 1989, 19 Pa.B. 3229; amended February 4, 2011, effective February 5, 2011, 41 Pa.B. 805). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-14 

formation of low permeability and provide a pathway for hydrocarbons and other fluids to flow 

more easily out of a formation and, ultimately, into a wellbore. In horizontal gas wells in 

unconventional formations, high volume hydraulic fracturing (HVHF, or just HF for short) is 

normally considered an essential part of the completion process (since gas production would be 

too low to justify the costs of drilling and completing a well in such formations). During the HF 

process, fluid (normally comprised of water and a variety of chemical additives to reduce the 

viscosity of the water; prevent microbial growth; disinfect the water; reduce interfacial tension; 

inhibit scale; etc.) is pumped into the production casing of a completed well, through 

perforations made in the casing, and into the target formation at pressures great enough to 

fracture the rock (King 2012). As fluid injection continues, fractures grow throughout the target 

formation; as the fractures grow, a proppant (sand) is added to the fluid. Once pumping stops and 

excess pressure is removed, the fractures attempt to close under the weight of the overlying 

strata, but the proppant keeps the fractures open—effectively increasing the permeability and, 

ultimately, the rate of fluid migration out of the formation (API 2009a). 

Technical concerns about hydraulic fracturing have tended to focus on three major issues: (1) 

transport of HF fluids and other contaminants (e.g., methane gas) from a fractured Marcellus 

formation into natural fractures where they could be transported long distances (thousands of ft) 

to USDW (Myers 2012, Saiers and Barth 2012); (2) induced seismic activity associated with the 

HF process; and (3) the specific chemical additives used in making up the HF fluid (and their 

toxicity). While well beyond the scope of our study of best practices to fully explore, we believe 

that there has been insufficient scientific study of the first issue to allow any firm conclusions to 

be drawn. Such studies would undoubtedly need to consider the full gamut of pathways (e.g., 

improperly cemented well casings) by which contaminants—both gases and liquids—either 

introduced or native to overpressurized formations such as the Marcellus could impact USDW. 

Certainly this complexity warrants continued study, both of new methods in well engineering 

and well completion as they become available, but also environmental data demonstrating well 

isolation has been successful in protecting the USDW. With respect to the second issue of 

induced seismic activity, we cite the recently published National Research Council (NRC) report 

which concluded that: (1) the process of hydraulic fracturing a well as presently implemented for 

shale gas recovery does not pose a high risk for inducing felt seismic events; and (2) injection for 

disposal of waste water derived from energy technologies into the subsurface does poses some 

risk for induced seismicity, but very few events have been documented over the past several 

decades relative to the large number of disposal wells in operation (NRC 2012 ). Best practices 

for selecting, handling, and disposing of HF chemicals are discussed in Chapter 4. 

H. Use of well development techniques other than hydraulic fracturing 

New York State has performed a technical review of possible future alternative well stimulation 

techniques to water-based hydraulic fracturing (which could largely eliminate the need for 

trucking water to well sites and presumably produce less waste), but at present these techniques 

appear to be limited to demonstration or pilot projects in the United States and none can be 

considered a best practice. Unfortunately, we lack the technical capacity and necessary 

experience to evaluate the potential of any of these methods to replace water-based HF in the 

future, but we provide the following material excerpted from New York’s draft assessment 

document (NYSDEC 2011) as an aid to state regulators that may wish to explore these options in 

the future: 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-15 

• Liquid CO2. The use of a liquid CO2 and proppant mixture obviously reduces the use of 

other additives. Once CO2 vaporizes, it leaves only the proppant in the fractures. The 

appropriate level of environmental review for this alternative, if proposed in New York, 

would need to be determined at the time of application. 

• Nitrogen-based foam. Nitrogen-based foam fracturing was used in vertical shale wells in 

the Appalachian Basin until recently. Nitrogen gas is unable to carry appreciable amounts 

of proppant and the nitrogen foam was found to introduce liquid components that can 

cause formation damage. 

• Liquified petroleum gas (LPG). More recently, New York looked into the use of LPG 

(primarily propane) which has the advantages of carbon dioxide and nitrogen noted 

above; additionally, LPG is known to be a good carrier of proppant due to the higher 

viscosity of the propane gel. Further, mixing LPG with natural gas apparently does not 

“contaminate” natural gas and the mixture may, therefore, be flowed directly into a gas 

pipeline and separated at the gas plant and recycled. LPG’s high volatility, low weight, 

and high recovery potential make it a particularly good fracturing agent. Use of LPG as a 

hydraulic fracturing fluid also inhibits formation damage which can occur during 

hydraulic fracturing with conventional fluids. Using propane not only minimizes 

formation damage, but also eliminates the need to source water for hydraulic fracturing, 

recover flowback fluids at the surface, and dispose of the flowback fluids. As a result of 

the elimination of hydraulic fracturing source water, truck traffic to and from the well site 

could be greatly reduced. Finally, since LPG is less reactive with the formation matrix, it 

is less likely that this technique would mobilize constituents that are ultimately 

discharged with the flowback fluid (NYSDEC 2011). 

I. Determining the extent of induced fractures 

There are two methods that can be used for determining the extent of induced vertical fracture 

growth by hydraulic fracturing. The first technique is through the use of either surface or 

downhole tiltmeters that are capable of measuring extremely small changes in the inclination of 

the Earth’s surface from level. Historically, tiltmeters have been used extensively for monitoring 

volcanoes, the responses of dams to filling, and small movements of potential landslides, but 

extremely sensitive (nanoradian) surface and downhole tiltmeters developed in the 1970s by 

Pinnacle (a Halliburton subsidiary) now allow for fracture mapping from either offset wells or 

from the surface; a new generation method can apparently map induced fractures from an active 

fracture well in real-time (API 2009a). The second technique produces a map of vertical fracture 

height growth based on data from passive micro-seismic monitoring that is capable of 

triangulating the sounds made by rock breaking up during shear fracturing. Micro-seismic 

measurements are typically made with: (1) a 200 to 400 ft long set of geophones placed in an 

offset well located within a few hundred ft of the well being fractured; or (2) an array of 

microphones placed at the surface. Micro-seismic monitoring makes it possible to determine 

such critical hydraulic fracturing parameters as vertical extent, lateral extent, azimuth, and 

fracture complexity (API 2009a). 

Micro-seismic data (from more than 3,000 HF applications) from Pinnacle (Fisher 2010, 

reprinted by King 2012) shows vertical fracture growth in hydraulically-fractured Barnett Shale 

wells typically extends hundreds to thousands of ft above and below the frac depth, but in no 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-16 

case was fracture growth observed closer than 2,800 vertical ft from USDW. Comparable data 

(from more than 300 fracs with micro-seismic data) from Pinnacle (Fisher 2010, reprinted by 

King 2012) suggest that the closest measured approach of Marcellus shale fractures in 

Pennsylvania to USDW was 3,800 vertical ft. As discussed in Chapter 1, these results generally 

support our recommendation that Maryland follow guidance from New York’s experience with 

unconventional shale gas development and not permit MSGD (or any other unconventional gas 

development) where the target formation occurs within 1,000 vertical ft of USDW or within 

2,000 vertical ft of the ground surface (NYSDEC 2011). 

Best practice is not to employ tiltmeter surveys or microseismic on every well, rather it is most 

commonly used to evaluate new techniques, refine the effectiveness of fracturing in new areas or 

formations, and in calibrating computer models of the fracturing process (API 2009a). There are 

no micro-seismic monitoring protocols or criteria established by regulatory agencies that are 

specific to HVHF. Nonetheless, operators can employ micro-seismic methods to monitor the 

hydraulic fracturing process and thus optimize the results for successful gas recovery. It is in the 

operator‘s best interest to closely control the hydraulic fracturing process to ensure that fractures 

are propagated in the desired direction and distance and to minimize the materials and costs 

associated with the process. Best practice would suggest that operators place multiple receivers 

on a wireline array in one or more offset borings (e.g., a new, unperforated well or an older well 

with production isolated) or in the treatment well during the HVHF process. At least one receiver 

should be in the treatment zone, with another located above and one below this zone. Maximum 

observation distances for microseisms should be within approximately 2,500 ft of the treatment 

well, with the distance dependent on formation properties and background noise levels. 

Locations are triangulated using the arrival times of the various p- and s-waves to the receivers in 

these wells, and using the formation velocities to determine the location of the microseisms. A 

multi-level vertical array of receivers can be used if only one offset observation well is available. 

The induced fracture is interpreted to lie within the envelope of mapped microseisms (NYSDEC 

2011). We highly recommend that a sufficient number (at least tens) of tiltmeter or seismic 

surveys be performed as part of MSGD in Maryland, so that the extent, geometry, and location 

of Marcellus fracturing can be adequately characterized. The goal would be to feed useful 

information back to the operators, so that subsequent hydraulic fracturing could be conducted 

more safely and effectively. Data from such surveys in Maryland (and other states) would also be 

deemed crucial in evaluating whether HVHF might eventually be safely conducted in locations 

where the target formation is located within 2,000 ft of the surface. 

 

J. Plugging 

The purpose of plugging a well is to: (1) prevent interzonal migration of fluids; (2) prevent 

contamination of freshwater aquifers, surface soils, and surface waters; and (3) conserve 

hydrocarbon resources either in the production zone or in potential production zones. Generally, 

contamination by an improperly plugged or abandoned well can occur in two ways: (1) the 

abandoned well can act as a conduit for fluid flow between penetrated strata, into USDW, or to 

the surface; or (2) contaminated water can enter the abandoned wellbore at the surface and 

migrate into USDW. Such contamination can be prevented by properly plugged a well. It should 

be noted that while plugging operations can prevent an abandoned well from becoming a conduit 

for contamination, well construction and completion methods also contribute to the prevention of 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-17 

contamination (API 2009b). Plugging should be considered a critical element of the well 

decommissioning process that also includes land reclamation. 

Well plugging operations are focused primarily on protecting USDW, isolating downhole 

formations productive of hydrocarbons or used for injection, and protecting surface soils and 

surface waters. A surface plug prevents surface water runoff from seeping into the wellbore and 

migrating into USDW cement plugs isolating hydrocarbon and injection/disposal intervals and a 

plug at the base of the lowermost USDW accomplishes this primary purpose. Surface water entry 

into an abandoned well is a concern because the water may contain contaminants from 

agricultural, industrial, or municipal activities. It is, therefore, recommended that operators set a 

cement plug at the base of the lowermost freshwater aquifer or USDW during plugging and 

abandonment operations applicable to the well. (NOTE: The cement plugs also work to protect 

surface soils and water from wellbore fluids by confining those fluids in the well.) In addition to 

the cement plugs described herein, many state and federal regulatory agencies require cement 

plugs across the base of the surface casing and in, or between, each producing and potential 

producing zone (API 2009b). 

All formations bearing usable quality water, oil, gas, or geothermal resources (e.g., coal seams) 

should be protected and/or isolated. The prevention of gas or fluid migration to other zones or to 

the surface is of primary importance. Open-hole plugs, casing plugs, or cement squeezed through 

casing perforations will isolate the target formations in most cases. However, special procedures, 

such as perforating casing and circulating cement, may be necessary to isolate that potential 

production or injection formations behind any uncemented or poorly cemented casing. It is 

important to prevent interzonal flow in an abandoned well so that such cross-flow does not 

interfere in the commercial exploitation of the zones through nearby wellbores. The operator 

should also: (1) set the required surface plugs; (2) remove the wellhead; (3) weld a steel plate on 

the surface casing stub; (4) fill in any well cellar; and (5) level the area. Casing strings left in the 

well should be cut off at least 3–6 ft below ground level (API 2009b). 

Pennsylvania21 and Colorado22 have enacted regulations governing plugging of gas wells that 

appear to be consistent with API’s recommended practices, but West Virginia and Ohio have not. 

Maryland also has what appear to be excellent regulations23 that are consistent with API 

recommendation for plugging of wells. Given the long expected time lags (of the order of 30 

years or more) between drilling and well decommissioning, the biggest problem that we 

anticipate with plugging of Marcellus wells in Maryland will be ensuring that the appropriate 

party is held accountable and has sufficient assets to do so. The costs associated with plugging 

wells that were poorly constructed in the first place can be extremely high (Mitchell amd 

Casman 2011), reinforcing the need to ensure that any Marcellus shale gas wells in Maryland are 

constructed to the highest standards. 

 

21 25 Pa. Code § 78.92 (relating to wells in coal areas—surface or coal protective casing is cemented); 25 Pa. Code 

§ 78.93 (relating to wells in coal areas—surface or coal protective casing anchored with a packer or cement); 25 

Pa. Code § 78.94 (relating to wells in noncoal areas—surface casing is not cemented or not present); 25 Pa. Code 

§ 78.95 (relating to wells in noncoal areas—surface casing is cemented); and 25 Pa. Code § 78.407 (relating to 

plugging gas storage wells). 22 COGCC Rule 319, Abandonment. 

23 COMAR 26.19.01.12 
K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-18 

K. Key recommendations 

3-A A best practice for anyone proposing to operate in Maryland should be adoption of API’s 

extensive guidelines for well planning—at least those elements that are clearly relevant to 

onshore development. Pre-permit site review should also be required. 

3-B Site selection is a critical aspect of well planning for multiple reasons discussed 

throughout the report. As discussed in Chapter 1, we are particularly concerned about 

drilling in areas where there is a high probability of encountering large underground 

voids (e.g., caverns, caves, mine workings, abandoned wells, etc.) that have the potential 

to cause a loss of fluid circulation during drilling and impose additional risks during the 

cementing process. Such hazards are locally common in western Maryland and we 

recommend that sites with a high probability of encountering such hazards be avoided. 

3-C Surface casing must be fully cemented from the bottom to the surface to provide total 

protection of all USDW. There may be situations (e.g., very deep wells) where fully 

cementing the intermediate casing to the surface may not be required, however. At a 

minimum, an absolute requirement should be that all flow zones (including USDW) must 

be fully protected through the use of cemented intermediate well casings. Where this 

cannot be accomplished feasibly with a single casing string, the use of multiple casing 

strings should be favored in the well design. 

3-D Maryland should consider amending its regulations to require SRCBL (or equivalent 

casing integrity testing) and other types of logging (i.e., neutron logging) as part of a 

cased-hole program. 

3-E Best practice would clearly call for use of pressure testing of Marcellus shale gas wells in 

Maryland, with specific criteria and technical details governing the conduct of such tests 

likely established through consultation with industry. Maryland’s current regulations with 

regard to pressure testing of cemented casings are even less specific than those 

established by neighboring states and appear to be in need of revision. 

3-F Use of BOPE with two or more redundant mechanisms should be considered a best 

practice for MSGD in Maryland. 

3-G We recommend that a sufficient number of tiltmeter or micro-seismic surveys be 

performed as part of any MSGD in Maryland, so that the extent, geometry, and location 

of Marcellus fracturing can be adequately characterized across the entire region. The 

principal goal of this effort would be to feed useful information back to the operators, so 

that subsequent hydraulic fracturing can be conducted more safely and effectively. Data 

from such surveys in Maryland (and other states) would also be deemed crucial in 

evaluating whether HVHF might eventually be safely conducted in locations where the 

target formation is located within 2,000 ft of the surface. 

3-H Maryland also has what appear to be excellent regulations that are consistent with API 

recommendation for plugging of wells. Given the long expected time lags (of the order of 

30 years) between drilling and well decommissioning, the biggest problem that we 

anticipate with plugging of Marcellus wells in Maryland will be establishing liability and 

ensuring that liable parties can be held accountable for performing this critical task. The 

costs associated with plugging wells that were poorly constructed in the first place can be 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

3-19 

extremely high, which reinforces the need to ensure that any Marcellus shale gas wells in 

Maryland are constructed to the highest standards. 

L. Literature cited 

API. 2009a. Hydraulic Fracturing Operations--Well Construction and Integrity Guidelines (API Guidance 

Document HF1, First Edition), Washington, DC: American Petroleum Institute. 

API. 2009b. Environmental Protection for Onshore Oil and Gas Production Operations and Leases (API 

RP 51R, First Edition), Washington, DC: American Petroleum Institute. 

API. 2010. Isolating Potential Flow Zones During Well Construction (API Standard 65--Part 2, Second 

Edition), Washington, DC: American Petroleum Institute. 

Davies, R. J. 2011. Methane contamination of drinking water caused by hydraulic fracturing remains 

unproven. Proceedings of the National Academy of Sciences USA 108: E871. 

Fisher, K. 2010. Data confirm safety of well fracturing. American Oil and Gas Reporter, July issue. 

Harrison, S. S. 1985. Contamination of aquifers by overpressurizing the annulus of oil and gas wells. 

Ground Water 23:317-324. 

Ingraffea, A. R. 2012. Fluid migration mechanisms due to faulty well design and/or construction: an 

overview of recent experiences in the Pennsylvania Marcellus Play (unpublished white paper), 

Physicians Scientists & Engineers for Health Energy. 

Jackson, R. B., S. G. Osborn, A. Vengosh, and N. R. Warner. 2011. Reply to Davies: Hydraulic fracturing 

remains a possible mechanism for observed methane contamination of drinking water. 

Proceedings of the National Academy of Sciences, USA 103:E872. 

King, G. E. 2012. Estimating frac risk and improving frac performance in unconventional gas and oil 

wells (paper SPE 152596). 

Lien, A. M., and W.J. Manner. 2010. The Marcellus shale: resources for stakeholders in the Upper 

Delaware watershed region. Pinchot Institute for Conservation. 

Mitchell, A. L., and E. A. Casman. 2011. Economic incentives and regulatory framework for shale gas 

well site reclamation in Pennsylvania. Environmental Science & Technology 45:9506-9514. 

Myers, T. 2012. Potential contaminant pathways from hydraulically fractured shale to aquifers. Ground 

Water 50:872-882. 

National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling. 2011. Deep Water: 

the Gulf Oil Disaster and the Future of Offshore Drilling (Report to the President). 

NRC. 2012. Induced Seismicity Potential in Energy Technologies (advanced copy released June 15, 

2012), Washington, DC: National Research Council. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

Osborn, S. G., A. Vengosh, N. R. Warner, and R. B. Jackson. 2011. Methane contamination of drinking 

water accompanying gas-well drilling and hydraulic fracturing. Proceedings of the National 

Academy of Sciences, U.S.A. 108:8172-8176. 

Saiers, J. E. and E. Barth. 2012. Comment by James E. Saiers and Erica Barth on "Potential contaminant 

pathways from hydraulically fractured shale to aquifers". Ground Water 50:826-828. 

Warner, N. R., R. B. Jackson, T. H. Darrah, S. G. Osborn, A. Down, K. Zhao, A. White, and A. Vengosh. 

2012. Geochemical evidence for possible natural migration of Marcellus Formation brine to 

shallow aquifers in Pennsylvania. Proceedings of the National Academy of Sciences, U.S.A. 

109:11161-11166. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-1 

4. Protecting water resources1

Water is central to the advancements in shale gas recovery that have revolutionized domestic 

natural gas resources in the past decade. High volume hydraulic fracturing (HVHF) with 

chemically-amended water enables extraction of large reserves previously considered 

economically unviable. Significant amounts of water are required for the process, and significant 

amounts of wastewater are produced. Wastewaters (commonly called flowback and production 

waters) are contaminated with anthropogenic chemicals associated with the hydraulic fracturing 

process and with naturally-occurring chemicals associated with the shale formation. The possible 

impacts of shale gas development on regional water resources (i.e., quantity and quality) must be 

considered at all phases of the life-cycle of well and gas field development. Figure 4-1 provides a 

life cycle representation for shale gas development at a single pad. The general concerns for 

freshwater resources and the generation of wastewater are presented, aligned with when they 

occur in the life cycle of development. Some aspects of potential water impacts (e.g., land 

clearing and stormwater runoff) can be generalized as associated with the development of any 

industrial site. Other aspects (e.g., concerns with managing chemicals and preventing spills) are 

specific to activities that use large quantities of chemicals in the open, frequently under 

suboptimal climatic conditions. Finally, other concerns (e.g., concerns regarding casing and 

management of produced brine) are specific to oil and gas drilling operations. 

A critical point shown in Figure 4-1 is that many potential impacts occur throughout 

development until closure (e.g., generation and management of surface runoff from the site), 

while other concerns (e.g., the effect of drilling on groundwater resources) may occur during a 

limited period of time. Further, there are additional concerns at the level of the entire resource 

development (the play) that must also be considered. The distributed nature of the activity (i.e., 

potentially hundreds of locations in western Maryland) raises specific issues with respect to 

watershed-wide effects. For example, it is important to consider the cumulative impact of water 

withdrawals for multiple wells and multiple pads, as well as the total volume of wastewater that 

will be generated by the formation once many hundreds of wells are in production. 

This chapter provides a summary of recommendations based on a review of the actual and 

proposed best management practices (BMPs) for shale gas development (MSGD2

) related to 

water acquisition and wastewater management in five states (WV, OH, PA, NY, and CO). Most 

of the practices either adopted or considered by Pennsylvania and West Virginia are applicable to 

Maryland, where geology, hydrology, and topography are very similar. Some practices that have 

been routinely employed in western states (e.g., evaporative concentration of wastes in open 

impoundments) are inappropriate for the mid-Atlantic region and cannot be recommended. We 

have also addressed some of the key regulatory and policy aspects in addressing 

water/wastewater issues associated with MSGD in Maryland. 

 

1

 Chapter co-authors: Jeanne M. VanBriesen, Ph.D., P.E. (Department of Civil and Environmental Engineering, 

Carnegie Mellon University, Pittsburgh, PA 15213); Keith N. Eshleman, Ph.D. (Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532); and Andrew J. Elmore, Ph.D. 

(Appalachian Laboratory, University of Maryland Center for Environmental Science, Frostburg, MD 21532) 2

 As elsewhere in this report, MSGD refers to Marcellus shale gas development. However, our review of actual and 

proposed BMPs in the five states covered all shale gas development, regardless of the target formation. 
K.N. Eshleman & A.J. Elmore (2013) 

4-2 

Pre

Development

Pad 

Development Drilling Completion via hydraulic fracturing Production Site Closure and Restoration

Life Cycle Phase

Fresh Water and Drinking Water Issues Waste Water Issues Water withdrawals from surface and ground water sources will occur. Alternative waters may be used (e.g., AMD, mine water, recycled produced water). Fresh water impoundments and temporary water transport systems may be built on site or in the development area. Ground water resources will be isolated from drilling and completion activities through appropriate well casing. Surface water runoff may occur from stormwater and can affect fresh water resources at the surface and in aquifers. Erosion and sediment controls will be employed to collect stormwater for use or treatment on site. Fresh and recycled water will be trucked to the pad site. Produced water will be stored on site with regularly scheduled collection via truck. Water is used in chemical manufacture, sand extraction, and energy generation necessary to produce the equipment and materials involved in the process of shale gas extraction. Chemicals will be brought to the site. Produced water may be partially treated and reused on site. Temporary impoundments will be closed. Storage tanks will be removed. Drill cuttings will be removed. Temporary chemical storage tanks will be removed. Stormwater and surface runoff will generate wastewater. Erosion and sediment controls will be employed to collect stormwater for use or treatment on site. Produced water will be collected and trucked to disposal or treatment. Early produced water (flowback) will be collected and may be treated on site for reuse or trucked off site for reuse, treatment or disposal. Drill cuttings and drilling muds will be collected for reuse or disposal. The well bore will be sealed. Wastewater is produced in chemical manufacture, sand extraction and energy generation necessary to produce the equipment and materials involved in the process of shale gas extraction. Impoundment liners and residuals will be collected and trucked to disposal. Partial reclamation of pad, including revegetation. Complete reclamation of pad and all developed area. Removal of access roads and pipelines. Chemical storage tanks and other temporary facilities may be built. Drilling and completion equipment will be brought to the site and staged. 

Figure 4-1. Water and wastewater issues across the life cycle of pad and well development for unconventional shale gas de
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-3 

A. Siting requirements: setbacks and restrictions 

As discussed in previous and subsequent chapters, site selection for well pads and wells is an 

extremely important aspect of MSGD. The first step to preventing negative environmental 

impacts is to make careful site selections and require adequate setbacks to reduce impacts to 

critical water resources. While water has a number of different values that require consideration 

(some of these are discussed in Chapter 6), we primarily address water used for humans in this 

section. 

In Allegany County (2011 estimated population of 74,692), 83% of the population uses surface 

water (community- provided) while 17% of the population uses groundwater (individual wells). 

In Garrett County (2011 estimated population of 30,051) 90% of the population uses ground 

water (predominantly individual wells: 70%), while 10% of the population uses communityprovided surface water. In Allegany County, two large drinking water systems (City of 

Cumberland and the City of Frostburg), one medium system (Midland-Lonaconing), and one 

very small system (Rawlings Heights) treat their surface water. Three medium systems (Eastern 

Region Allegany, Lavale Sanitary Commission, Western Region Allegany) and two small 

systems (Bel-Air Pinto and Southern Region Allegany) purchase surface water from another 

provider. Six very small systems (Barrelville, Green Ridge, Midlothian, Reckley Spring, and 

Rocky Gap) use groundwater, and one other system (Mount Savage) uses groundwater under the 

influence of surface water. An additional three non-transient non-community systems and 36 

transient non-community water systems are predominantly on groundwater (only Rocky Gap 

State Park uses surface water). For the City of Cumberland, the source water is the Lake Koon 

and Gordon reservoirs in Pennsylvania, part of the Evitts Creek watershed. The City of 

Frostburg receives its water from the Piney Dam Reservoir in Garrett County, MD, as well as 

from two deep wells in the Pocono aquifer and a series of springhouses. These sources are mixed 

prior to treatment. The Midland-Lonaconing system uses several reservoirs (Midland Gilmore, 

Charlestown, Koontz) that are part of the Georges Creek watershed (Potomac River watershed) 

and all fed by headwater streams. This surface water is supplemented by several groundwater 

wells that either pump into the reservoir or the plant. 

All public drinking water systems in Garrett County are small: two systems (Friendsville and 

Oakland) are on surface water and three systems (McHenry, Mountain Lake Park, Grantsville) 

are on groundwater. Two very small systems (Bloomington and Kitzmiller) are on surface water, 

while the balance (Backbone Mountain, Crellin, Gorman, Meadow Mountain, Meadow Park, 

Savage Mountain, Accident, Deer Park, and White Oak) are on groundwater. An additional 11 

non-transient non-community systems and 75 transient non-community water systems are all on 

groundwater. 

Sufficient water is impounded for the surface water plants in the region, but historical water 

supply problems suggest vulnerability on quantity should additional withdrawals take place from 

the reservoirs or the tributaries that feed them at certain times of the year. Further, source water 

assessment documents for Evitts Creek watershed indicate concerns with turbidity increases 

associated with rainfall events that would likely be exacerbated if development did not include 

adequate sedimentation controls (PADEP 2003). Similarly, Piney Dam Reservoir exhibits 

elevated nutrients and sodium levels, likely due to agricultural runoff and development, 

increasing the risk of harmful algal blooms that challenge drinking water treatment systems 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-4 

(Castro et al. 2001). As indicated by the assessment above, significant numbers of western 

Maryland residents rely on groundwater for their domestic water use. 

Particularly in Garrett County, private well supply dependence (see Figure 4-2) suggests a strong 

need for setbacks and siting criteria that can effectively reduce the risks to these resources posed 

by surface spills (or incorrect drilling and cementing techniques in well development). Therefore, 

public and private water supply well identification should be part of the initial permit application 

process. Setbacks from existing water wells should be incorporated into siting requirements. 

Setbacks should be selected based on the source (groundwater wells vs. surface water intakes) 

and based on the area of influence for a well (the region of the aquifer affected by the pumping) 

and the mixing zone for a surface water system. Large public system wells have more impact on 

the aquifer, and thus, surface disturbance or accidental spills over a larger surface area could 

affect public system wells, necessitating larger setbacks. For surface waters, an upstream spill 

will have the largest impact if it occurs close to the intake where natural dilution capacity will be 

the smallest; thus surface water intake setbacks provide a buffer, usually called a mixing zone, 

for dilution of a spilled material upstream of an intake. 

Figure 4-2. Map of density of public and private wells in western Maryland. Note: 23 acre unit is equivalent to 106

sq. ft. 

Setbacks for public and private wells in current regulations are variable, although it has been 

recommended that both Pennsylvania and New York establish 500 ft. setbacks for private wells. 

Such setbacks could be waived with owner’s permission. West Virginia and Pennsylvania 

presently enforce 1,000 ft. setbacks to surface intakes and groundwater wells used for public 

water supply systems, but it has been recommended that New York impose a 2,000 ft. setback 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-5 

for public system intakes (NYSDEC 2011). Therefore, based on our review of what is being 

done in other states, we recommend that a best practice for Maryland would be to establish a 

regulation of 500 ft. and 2,000 ft. setbacks (measured from the well pad, not from the individual 

wellbores) for private wells and public system wells, respectively, and a setback of 2000 ft. 

upstream from public surface water supply intakes. 

Both Pennsylvania and West Virginia have presumption of contamination rules for drinking 

water wells that contain contaminants after drilling has taken place. Currently, the zone of 

presumptive liability is 1,000 feet. The Pennsylvania Governor’s Marcellus Shale Advisory 

Commission recommended increasing the liability zone to 2,500 feet from public water supply 

wells (Marcellus Shale Advisory Commission 2011). The Center for Rural Pennsylvania 

completed a report based on analysis of water quality in private water wells in proximity to 

Marcellus gas wells, which recommended increasing the zone of liability to 3,000 feet from 

private water wells (Boyer et al. 2011). In 2012, the Maryland legislature established a rebuttable 

presumption that drilling or fracking activities were the cause of drinking water contamination if 

the contamination occurred within 2500 feet of the vertical borehole and within 365 days3

. Predrilling sampling is not required, and refusal of such sampling vacates the landowner’s right to 

compensatory damages. We support this regulatory structure and recommend that all water 

quality data collected through pre-drilling testing be provided to the appropriate Maryland 

agency as well as to landowners to increase the information available related to groundwater 

resources regionally. Pre-development notification should be made to public and private drinking 

water well owners. Further, we recommend requiring post-development assessment of impacts to 

drinking water wells. These issues are discussed further in section B below. 

Due to the heavy reliance on impounded surface water from headwater streams in small, mostly 

forested watersheds as a drinking water source for the majority of Allegany County residents, 

water withdrawal plans and drill pad siting plans should be assessed within the context of 

watershed protection plans previously developed by the drinking water providers. Source water 

assessment and protection plans typically include source water delineation maps, transportation 

corridors, and existing potential sources of water quality impairment information that can assist 

permitting and siting decisions. Any drinking water provider that does not have a watershed 

protection plan should be required to develop one in advance of any approved development 

within its source watershed. To avoid contamination of all streams and rivers, no drilling should 

be conducted on floodplains, nor should materials or equipment be staged on floodplains. 

Setbacks should be extended for on-site staging and storage of hazardous materials and for 

eventual collection tanks for produced water. Setbacks from streams and wetlands are also 

recommended to reduce the potential for surface spills affecting source waters; consistent with 

recommendations in Chapter 6, a 300 ft. buffer from all streams, wetlands, and springs should be 

enforced to protect surface water quality. As noted above, Maryland should enforce a 2,000 ft. 

setback from drinking water intakes for surface water plants to reduce direct contamination in the 

event of spills on site. Watershed protection plans, specific for each water provider, may in some 

cases recommend greater setbacks due to unique conditions within source watersheds. In 

particular, both large community systems in western Maryland (City of Cumberland and City of 

Frostburg) receive most of their source water from Pennsylvania watersheds, so an assessment of 

current oil and gas water withdrawals and permitted development within the upstream basins in 

 

3

 Md. Env. Code § 14-110.1 (H.B. 1123). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-6 

Pennsylvania is clearly warranted. We recommend flexibility in the setback statute to enable 

requirement of larger setbacks when warranted by analysis of watershed protection plans from 

drinking water systems. 

B. Monitoring of water resources prior to, during, and following development 

As discussed in section A above, routine pre-drilling assessment of groundwater quality should 

be required in Maryland. Pre-drilling public notification should also be part of the permit 

process, thus allowing well owners outside the pre-drilling survey area to pursue their own water 

quality sampling, if desired. In Pennsylvania, citizens have to ‘opt-in’ for notification of drilling 

in their area. Maryland should proactively publicize planned activities during the pre-drilling 

phase of MSGD. The identification of all potentially affected groundwater wells and pre-drilling 

testing of these wells is a best management practice that should be required in Maryland. Predrilling testing should be required to be conducted by the operator and the results provided to the 

Maryland Department of the Environment and to the well owner. Post-drilling testing is often at 

the discretion of the well owner, but a best management practice that would enable improved 

understanding of the potential for effects on groundwater would be to require post-drilling and 

completion testing by the operator for all wells within a pre-determined potentially affected 

region for a specified time period after completion of well construction activities. As noted 

above, in Pennsylvania this is 1,000 ft., but longer distances are likely relevant for the more 

intensive activities associated with horizontal drilling and completion and have been 

recommended by several Pennsylvania studies (Boyer et al. 2011, Marcellus Shale Advisory 

Commission 2011). 

More extensive groundwater testing (e.g., up to 1⁄2 mile from the planned activity) would likely 

produce a better baseline of water quality in the region. Since Maryland does not have extensive 

information on groundwater in the western part of the state, extensive pre-drilling testing could 

provide important information to MDE to be used in addressing potential impacts of 

development on groundwater resources. Testing should include, at a minimum, the well yield 

and the following water quality parameters: conductivity, total suspended solids or turbidity, 

total dissolved solids (TDS), chloride, bromide, sulfate, barium, strontium, naturally occurring 

radioactive materials (NORM), chemical oxygen demand (COD), and BTEX (benzene, toluene, 

ethylbenzene, and xylene). Currently, MGS tests for a wide variety of natural and anthropogenic 

compounds in well samples (see Table 4-1). We recommend using this same suite of analyses for 

pre- and post-drilling sampling to provide the most comprehensive information on conditions in 

the subsurface and add to the repository of knowledge in Maryland about groundwater resources. 

We support the proposal that water samples be collected by qualified professionals and analyzed 

utilizing an approved analytical laboratory (i.e., one approved by the Environmental Laboratory 

Accreditation Program, ELAP), including the use of proper sampling and laboratory protocols in 

addition to the use of proper sample containers, preservation methods, holding times, chain of 

custody, analytical methods, and laboratory quality assurance/quality control (QA/QC) 

procedures (NYSDEC 2011). As noted above, all data should be shared with MDE and MGS. In 

addition, Maryland should require full disclosure of hydraulic fracturing chemicals well in 

advance of their use (see Section I), thus enabling pre-development and post-development 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-7 

groundwater monitoring efforts to include some of these substances. Post-completion well 

testing should include the same wells tested in the pre-drilling phase of development. 

Table 4-1. 

Recommended water-quality constituents to be analyzed in groundwater in 

pre- and post-drilling assessment of Marcellus shale area. 

MAJOR IONS AND INDICATORS

Calcium 

Magnesium 

Sodium 

Potassium 

Nitrate plus nitrite 

Nitrite 

Ammonia 

Sulfate 

Chloride 

Alkalinity 

Specific conductance 

Methane 

Fluoride 

Bromide 

Silica 

Color 

pH 

Dissolved oxygen 

Total dissolved solids 

(residue at 180o

 C.) 

Total organic carbon 

TRACE ELEMENTS

Aluminum 

Antimony 

Arsenic 

Barium 

Beryllium 

Boron 

Cadmium 

Chromium 

Cobalt 

Copper 

Lead 

Lithium 

Iron 

Manganese 

Molybdenum 

Nickel 

Selenium 

Silver 

Strontium 

Thallium 

Uranium 

Vanadium 

Zinc 

HYDROCARBONS AND METHANE ISOTOPES RADIONUCLIDES 

Methane 

Ethane 

Ethene 

Propane 

2

H-CH4 (if sufficient methane available) 13C-CH4 (if sufficient methane available) 

Gross alpha-particle activity 

Gross beta-particle activity 

(both analyzed within three days of sample 

collection and again at 30 days after sample 

collection) 

Radon-222 

New developments in sensing technology have enabled improved monitoring at a variety of 

locations with the potential to be affected by MSGD in Maryland. Drinking water providers in 

Pennsylvania and West Virginia have installed a network of source water monitoring equipment 

for early detection of changes in conductivity (that can indicate salt levels are rising). The River 

Alert Information Network (RAIN)4 enables early detection of changes in source water 

conditions that affect drinking water treatment and finished water quality for consumers. RAIN 

is a collaborative effort among drinking water plants, PADEP, West Virginia Department of 

Environmental Protection (WVDEP), and USEPA, with joint funding for the sensors, 

deployment, and maintenance. RAIN should be extended into the Marcellus development area in 

western Maryland, with funding provided to drinking water utilities to install monitors near their 

intakes. Drinking water utilities have the technical expertise to operate and maintain these 

sensors and can provide early notification of any significant changes in water quality. Drinking 

water treatment plants operating in western Maryland should also increase their source water 

monitoring and specifically include bromide in their routine analyses. In other shale states, 

universities and watershed groups have also been involved in enhanced water sampling programs 

to provide baseline information on water quality and to alert the public when changed indicate 

 

4

 Information on RAIN is available at www.3rain.org. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-8 

problems that might be associated with shale gas development activities. These organizations can 

be involved (and are already involved to some degree) within Maryland as well. Routine 

sampling and the installation of real time sensors can provide useful data for understanding 

assessing any impacts of MSGD on water resources in the state). MDE should consider 

leveraging existing monitoring networks run by universities, watershed groups and other 

organizations as a way of capitalizing on existing datasets for baseline characterization. 

C. Water pollution, stormwater management, and erosion and sediment 

control across the life cycle 

Development of shale gas begins as many other types of construction projects do with clearing 

and leveling of land for the creation of a well pad; additional cleared acreage would likely be 

needed for roads, impoundments, pipelines, and utility corridors (see Chapter 1). One of the 

challenges for water associated with land clearing is stormwater runoff from drilling pads, 

including erosion and sedimentation and wash-off of any chemicals that have been spilled onto 

the pad during the various phases of an operation. Runoff of this type has the potential to affect 

downstream human water use as well as aquatic habitat, biodiversity, and wildlife (see Chapter 

6). For this reason, implementation of effective BMPs for stormwater pollution and erosion and 

sediment controls will be critical in managing potential water quality impacts of MSGD. 

Surface water pollution in the U.S. is primarily addressed by the Federal Clean Water Act. The 

Clean Water Act (CWA) prohibits the discharge of pollutants by point sources into waters of the 

U.S., except in compliance with certain provisions of the Act, specifically section 402, 33 U.S.C. 

1311(a). Section 402 establishes the National Pollutant Discharge Elimination System (NPDES) 

under which USEPA, or an authorized state agency, may issue permits that allow the discharge 

of pollutants into U.S. waters. In developing effluent limitations for an NPDES permit, limits 

based on available technology (i.e., technology-based effluent limits) and on the water quality 

standards of the receiving water (i.e., water quality-based effluent limits) must be considered. 

Technology-based effluent limits for direct discharges from oil and gas extraction facilities into 

surface waters are found in 40 CFR Part 35, Subpart C. The effluent guidelines thus establish 

best practicable control technology currently available for on-shore oil and gas extraction 

facilities are as follows: “there shall be no discharge of waste water pollutants into navigable 

waters from any source associated with production, field exploration, drilling, well completion or 

well treatment (i.e., produced waters, drilling muds, drill cuttings, and produced sand).” The 

importance of this “no discharge” limit is that oil and gas facilities are not required to apply for 

an NPDES permit and that states can use their own authority to ensure that the “no discharge” 

requirement in the effluent guidelines is properly applied and that operator compliance is 

demonstrated5

. The “no discharge” limit has obvious important implications for how the wastes 

(e.g., flowback, produced water, drilling muds, etc.) generated by onshore oil and gas facilities 

must be handled under federal law (see Sections G and H below). In addition to regulating such 

direct discharges, USEPA’s regulations also address (1) indirect releases of wastewaters into 

U.S. waters such as by publicly owned treatment works (POTWs) that have received oil and gas 

 

5 Attachment to memorandum from James Hanlon, Director of EPA’s Office of Wastewater Management, to the 

USEPA Regions titled “Natural Gas Drilling in the Marcellus Shale under the NPDES Program” (March 16, 

2011). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-9 

wastes; or (2) direct discharges from centralized treatment facilities that are subject to their own 

technology-based and water quality-based effluent guidelines. 

The CWA also gives USEPA (and authorized state programs) the authority to regulate 

stormwater pollution under a separate NPDES permitting program. Impervious surfaces, such as 

buildings, homes, roads, sidewalks, and parking lots, can significantly alter the natural hydrology 

of the land by increasing the volume, velocity, and temperature of runoff and by decreasing its 

infiltration capacity. Increasing the volume and velocity of stormwater runoff can cause stream 

bank erosion, flooding, and degradation of stream aquatic habitat. As stormwater runoff is 

produced, it can pick up trash, debris, and various pollutants such as sediment, oil and grease, 

pesticides and other toxics. Changes in ambient water temperature, sediment, and pollutants in 

stormwater runoff can be detrimental to aquatic life, wildlife, habitat, and human health. Soil 

exposed by construction activities is especially vulnerable to erosion. Excess sediment can 

increase the turbidity of receiving surface waters, reduce the amount of sunlight reaching aquatic 

plants, clog fish gills, and smother aquatic habitat and spawning areas. Therefore, the primary 

stormwater pollutant of concern from construction is usually sediment, and practices must be 

implemented to effectively control runoff and associated stormwater pollution. USEPA 

regulations require operators disturbing one acre or more of land6

 (including smaller individual 

areas that are part of larger developments) to apply for coverage under a NPDES construction 

general permit for stormwater discharge and develop and implement a Stormwater Pollution 

Prevention Program (SWPPP). An SWPPP is a site-specific, written document that: (1) identifies 

potential sources of stormwater pollution at the construction site; (2) describes practices (BMPs) 

that will be employed to reduce pollutants in stormwater discharges from the site; and (3) 

identifies procedures that an operator will implement to comply with the terms and conditions of 

a construction general permit. Pollution reduction is most often achieved by controlling the 

volume of stormwater runoff (e.g., taking steps to allow stormwater to infiltrate into the soil). 

As in point source permitting, Maryland is also authorized to issue coverage under the NPDES 

construction general permit for stormwater discharges and has issued its own guidance 

documents and technical design manuals to aid in development of SWPPPs and implementation 

of BMPs for stormwater, erosion and sediment controls.7

 While Maryland appears to have a 

robust program for controlling stormwater pollution, we believe there is a significant regulatory 

impediment to effective implementation of BMPs to address stormwater pollution impacts 

associated with MSGD in the state and elsewhere. First of all, as amended by the Energy Policy 

Act of 2005, the CWA (section 402(1)(2) and 502(24)) specifically exempts oil and gas 

operations from most industrial stormwater permitting requirements by USEPA or by those 

states with approved NPDES programs (such as Maryland)8,9. Specifically, the section of the act 

reads as follows: “All field activities or operations associated with oil and gas exploration, 

production, processing, or treatment operations or transmission facilities, including activities 

necessary to prepare a site for drilling and for the movement and placement of drilling 

 

6 Some states grant variances for activities that disturb less than five acres of land. 7

 Maryland Stormwater Design Manual, Volumes I and II (effective October 2000, revised May 

2009);http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesign

Manual/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx 

8

 40 CFR § 122.26 Storm water discharges. 

9

 Ibid., 5 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-10 

equipment, whether or not such field activities or operations may be considered to be 

construction activities, except in accordance with paragraph (c)(1)(iii) of this section. Discharges 

of sediment from construction activities associated with oil and gas exploration, production, 

processing, or treatment operations or transmission facilities are not subject to the provisions of 

paragraph (c)(1)(iii)(C) of this section.”10 While exempted from NPDES industrial stormwater 

permitting, it is noted in the same statutes that the USEPA “encourages operators of oil and gas 

field activities or operations to implement and maintain best management practices (BMPs) to 

minimize discharges of pollutants, including sediment, in storm water both during and after 

construction activities to help ensure protection of surface water quality during storm events. 

Appropriate controls would be those suitable to the site conditions and consistent with generally 

accepted engineering design criteria and manufacturer specifications. Selection of BMPs could 

also be affected by seasonal or climate conditions.” 11

The importance of this exemption is that, unlike an entire suite of different types of industrial 

activities and operations12 that are not exempted from industrial stormwater permitting under the 

CWA, USEPA lacks the authority to regulate stormwater pollution from oil and gas activities in 

the same way that it would do so for these other industrial activities. In Maryland, which is 

authorized by USEPA to do NPDES industrial stormwater permitting, oil and gas extraction sites 

are not statutorily exempted from the sediment and erosion control program. However, oil and 

gas extraction sites are not considered “hotspots” for stormwater pollution impacts, although 

they may meet the definition13 of “hotspots”. Unlike most other industrial operations with 

equivalent (or perhaps even lower) risks of impacting surface water quality that are required to 

obtain an NPDES industrial permit and implement stormwater pollution prevention plans that 

address pollution both during and after construction, oil and gas operators are merely encouraged

to implement BMPs to control stormwater pollution and can be covered under the general 

construction permit14. USEPA and the approved state NPDES programs such as those in 

Maryland may be hampered in their efforts to control stormwater pollution from MSGD due to 

this exemption in federal law. 

Other than consistency with the federal exemption, there is no compelling reason for Maryland 

to exempt oil and gas extraction activities from its industrial stormwater permitting requirements. 

Designation as a hotspot has practical implications for management of stormwater. Typically, at 

 

1040 CFR § 122.26(a)(2)(ii) 

11Ibid. 

12Including vehicle salvage yards and recycling facilities, vehicle service and maintenance facilities, vehicle and 

equipment cleaning facilities, fleet storage areas, industrial sites, marinas, outdoor liquid container storage 

facilities, and outdoor loading/unloading facilities; see Maryland Stormwater Design Manual, Volumes I and II 

(effective October 2000, revised May 2009); Appendix D.6 Industrial Stormwater Permit Requirements; 

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManu

al/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx 13A stormwater hotspot is defined as a land use or activity that generates higher concentrations of hydrocarbons, 

trace metals or toxicants than are found in typical stormwater runoff, based on monitoring studies . See Maryland 

Stormwater Design Manual, Volumes I and II (effective October 2000, revised May 2009); Chapter 2.8 

Designation of Stormwater Hotspots; 

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManu

al/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx 14 Operations that result in disturbances of less than five acres of total land area are also exempted under 40 CFR § 

122.26(b)(14)(x). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-11 

construction sites where the primary concern is erosion and downstream sedimentation, SWPPPs 

tend to emphasize BMPs that promote infiltration into the ground as a primary means of 

reducing stormwater discharges and thus associated erosion and sedimentation problems. 

Performance standards developed in Maryland through largely urban stormwater control 

emphasize site designs that maximize pervious areas for stormwater treatment (standard no. 1) 

and promote infiltration through the use of structural and non-structural methods (standard no. 

2)15. However, for hotspots, where untreated stormwater runoff cannot be allowed to infiltrate 

into the ground, Maryland applies differential requirements to prevent groundwater 

contamination. Since oil and gas development sites are more similar to hotspots than to urban 

development sites, Maryland should review its stormwater regulations to ensure oil and gas 

extraction operations are managed in accordance with their characteristics, rather than through a 

statutory exemption. The use of a generic SWPPP, such as is often developed for residential 

subdivisions, is not the correct approach for managing stormwater pollution from shale gas 

operations. 

The primary goal, intent, and spirit of the CWA is found in the first sentence of the act [Section 

101(a)] where it states that the legislation is meant to “restore and maintain the chemical, 

physical, and biological integrity of the Nation’s waters”. While the restoration component of 

the CWA is largely being dealt with by the states through regulation of point and non-point 

discharges of water quality pollutants, the goal to maintain water quality in situations where 

impairment is not presently an issue is addressed under the federal anti-degradation policy. This 

regulatory policy, described in Section 303(d) of the CWA, is designed to prevent deterioration 

of existing levels of high or exceptional water quality in areas where such conditions exist. The 

federal policy requires states to develop rules and implementation procedures to protect existing 

uses of such waters and to prevent such waters from being degraded (unless the action 

responsible for the deterioration provides an important social or economic benefit). Each state’s 

anti-degradation rules and implementation procedures must be included in the state’s water 

quality standards (WQS). In addition, the federal rules16 require that: 

• Existing in-stream water uses and the level of water quality necessary to protect the 

existing uses shall be maintained and protected. 

• Where the quality of the waters exceeds levels necessary to support propagation of fish, 

shellfish, and wildlife and recreation in and on the water, that quality shall be maintained 

and protected unless the State finds, after full satisfaction of the intergovernmental 

coordination and public participation provisions of the State's continuing planning 

process, that allowing lower water quality is necessary to accommodate important 

economic or social development in the area in which the waters are located. In allowing 

such degradation or lower water quality, the State shall assure water quality adequate to 

protect existing uses fully. 

• The state shall assure that there shall be achieved the highest statutory and regulatory 

requirements for all new and existing point sources and all cost-effective and reasonable 

best management practices for non-point source control. 

 

15 Maryland Stormwater Design Manual, Volumes I and II (effective October 2000, revised May 2009); Chapter 1.0 

Introduction; 

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManu

al/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx 16 40 CFR §131.12 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-12 

• Where high quality waters constitute an outstanding national resource, such as waters of 

national and state parks and wildlife refuges and waters of exceptional recreational or 

ecological significance, that water quality shall be maintained and protected. 

Essentially, under federal rules, each state’s anti-degradation policy must be implemented under 

a three-tiered program: 

• “Tier 1”, that protects "existing uses" and provides the absolute floor of water quality for 

all waters of the United States [Section 131.13(a)(1)]; 

• “Tier 2”, that includes “high quality waters” (HQW) in which water quality exceeds that 

necessary to protect the Section 101(a)(2) goals (fishable and swimmable). Water quality 

may be lowered under certain conditions, but never below the level necessary to fully 

protect the “fishable and swimmable” and other existing uses [Section 131.12(a)(2)]; and 

• “Tier 3”, that are “outstanding national resource waters” (ONRW) in which only 

temporary reductions in water quality are allowed [Section 131.12(a)(3)]. 

Maryland adopted its anti-degradation policy as part of the WQS in 1985 and revised its policy 

in 2001. In 2004, Maryland adopted its current Tier II implementation policy and promulgated a 

list of 87 Tier II (i.e., HQW) stream segments based on established criteria of biological 

integrity; the majority of these Tier II segments are located in western Maryland (Figure 4-3). 

Maryland’s current Tier II policy states that “where water quality is better than the minimum 

requirements specified by the WQS, that water quality shall be maintained”. MDE will enforce 

the state Tier II policy by requiring that “applicants for proposed amendments to county plans or 

discharge permits for discharge to Tier II waters that will result in a new, or an increased, 

permitted annual discharge of pollutants and a potential impact to water quality, shall evaluate 

alternatives to eliminate or reduce discharges or impacts”. A Tier II anti-degradation review is 

required for permits involving individual discharges of at least 5,000 gallons per day; however, 

lesser proposed point discharges—and presumably non-point source discharges—of pollutants 

that could potentially contribute to significant degradation of water quality (especially of small 

streams) are exempted from anti-degradation review. Given this necessary trigger and the fact 

that point discharges from oil and gas development cannot be permitted as discussed earlier, we 

do not believe that MSGD would trigger a Tier II anti-degradation review in Maryland under 

current policy. For this reason, Maryland might wish to consider ways of strengthening its antidegradation policy to take account of the impacts of non-point source pollution that are a major 

threat to its high quality waters. One way that this might be accomplished would be by revising 

the WQS rules to require that any land development practices (e.g., forest management, MSGD, 

etc.) conducted in Tier II watersheds meet an anti-degradation standard.17

Based on review of stormwater management practices in other states, we recommend the 

construction of properly bermed “zero-discharge” pads that effectively collect all water on a pad 

site and enable the reuse of this water during drilling and completion operations. This practice 

requires careful grading during the pad construction process, so that water (i.e., mostly excess 

precipitation onto the pad, but also any other liquids) can flow by gravity to a single location on 

the pad where these liquids can be collected on a regular basis—typically using vacuum trucks. 

A berm around the entire pad should be designed to prevent any stormwater from being 

 

17 The state of Washington has a similar approach for applying anti-degradation rules to forest practices, and Oregon 

is considering such an approach (State of Oregon Department of Environmental Quality, 2010). 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-13 

discharged from the pad, except for the entrance road that should be elevated slightly above the 

pad to prevent runoff by the road. The entire pad must be underlain with a heavy impervious 

synthetic liner (comparable to liners used by landfills). Any areas where mechanized equipment 

will operate should be overlain with a composite decking material to protect the liner from 

abrasion and prevent infiltration (Lien and Manner 2010). 

 

Figure 4-3. Map showing locations of Tier II (i.e., HQW) streams (and catchments associated with these streams) 

and waterbodies greater than 1.5 acres in western Maryland. 

One of the weaknesses of this approach is that the system relies on coordination of active 

(vacuum trucks, water reuse) and passive (berms, liners) stormwater pollution prevention 

measures. In Maryland’s seasonally wet climate, it’s likely that well pads would overflow once 

active management ends. Since personnel are only expected to be on site continuously during 

active drilling and completion phases of development of a particular well, it is imperative to 

consider how these pads will function after well completion, or between different rounds of 

activities (wells completed at different times from the same pad). Since activities at the pad site 

may cycle through periods of active development and periods of production, pad reclamation to 

manage stormwater may have to occur multiple times. There are two options for managing 

runoff from drill pads between episodes of drilling: (1) the pads could be revegetated and 

restored to original condition any time operations cease for a defined time period (i.e., this would 

avoid excess runoff that was not being managed); or (2) the developed area could remain 

disturbed and a stormwater collection and management system could remain in place. The best 

solution for addressing both quality (i.e., suspended solids) and quantity (i.e., peak discharge) 

issues would be through construction of a below-grade lined pond adjacent to the bermed zerodischarge pad that could be used as a sump during active stormwater management phases and 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-14 

easily converted into a retention pond prior to any passive phases. Regular periodic (annual) 

maintenance of the pond would also be needed to ensure that the system is functioning correctly 

at all times. Additional water quality treatment could be obtained through operation of a 

constructed wetland sited downstream of the pond outlet. 

Related to stormwater management, operators would be required to develop and implement 

erosion and sediment control plans. These plans usually include BMPs for: (a) grading and 

stabilization to minimize erosion during development; (b) water conveyance plans for clearwater diversions around the development area to reduce stormwater that picks up sediment on 

the site; (c) erosion control that reduces the velocity of surface flows; (d) filtering and sediment 

trapping systems to collect sediment and prevent its discharge from the site; and (e) dewatering 

practices, if applicable to a site. Some plans also specify reclamation requirements, including 

restoration of grades and re-vegetation to prevent post-development changes in sediment loads 

from the site. Plans are typically certified by a registered professional engineer (PE). Each of 

these elements should be addressed in Maryland’s regulations. Soil erosion and sediment control 

plans should also be required for the development of new roads to sites. Stream crossings and 

development through wetland areas should be avoided (see Chapter 6 also). In addition, as 

recommended for New York and Pennsylvania, the design of all stormwater control structures to 

address erosion and sedimentation should be based on a 10yr/24hr rainstorm (i.e., the rainstorm 

with a duration of 24 hours that occurs, on average, once every ten years), as opposed to the 

2yr/24hr storm that occurs more frequently. Given the complexities in addressing how active and 

passive stormwater management will occur, we also recommend that the state ensure that Soil 

Conservation Districts, which currently review and approve sediment control plans and who are 

most knowledgeable for their geographic area are on-site during all major 

construction/deconstruction activities. Post-construction inspections of stormwater structures by 

MDE and the relevant Soil Conservation District personnel should occur prior to well drilling 

and completion. 

On January 27, 2012, Maryland enacted new regulations for soil erosion and sediment control 

(MDE 2011). As part of this new regulation, each county is required to draft erosion and 

sediment control ordinances by January 2013. A model ordinance was published by Maryland in 

February 2012 (MDE 2012). The model ordinance includes an exemption for clearing or grading 

activities that disturb less than 5,000 square ft. of land area (~ 0.1 acre), which is a fairly typical 

exemption that is unlikely to affect shale gas pads (typically on the order of 4-6 acres in size). In 

the Maryland model ordinance, Erosion and Sediment Control (ESC) plan review is required 

prior to permit approval. This is ideal and should be retained (some state regulations have 

exemptions that pertain specifically to oil and gas development18). Garrett and Allegany County 

should follow the Model Ordinance proposed by MDE, but should also require consideration in 

ESC plans of the potential effects of multiple clearings in relatively close proximity. Exemptions 

for small sites should not be enacted. Maryland should also evaluate potential issues associated 

 

18 For example, it is our understanding of Pennsylvania’s regulations that gas exploration and extraction facilities 

that result in disturbance of fewer than five acres are not required to obtain an “Erosion and Sediment Control 

Permit”. For such facilities (e.g., well pads), a “Permit Application for Drilling or Altering a Well” (5500-

PMOG0001) is sufficient. An Erosion and Sediment Control Plan must still be developed, but the plan is not 

subject to regulatory review and approval before construction. This is in contrast to most other construction 

activities, which are subject to erosion and sediment control requirements at one acre or greater under the 

Pennsylvania Chapter 102 requirements and NPDES requirements. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-15 

with stormwater, sedimentation and erosion within the context of multiple simultaneous MSGD 

sites and use its discretionary authority to require individual stormwater permits when warranted. 

ESC plans will also be critical in managing potential impacts on downstream water users. 

Maryland should ensure that public water supplies downstream of permitted MSGD activities 

should be notified prior to such activities. 

With respect to specific BMPs, operators should be strongly encouraged to consult Maryland’s 

Stormwater Design Manual and an industry document entitled “Guidance Document, Reasonable 

and Prudent Practices for Stabilization (RAPPS) at Oil and Natural Gas Exploration and 

Production Sites” published by API. The latter report describes a host of specific operating 

practices and control measures that have been used and tested by oil and natural gas operators to 

effectively control erosion and sedimentation from stormwater runoff resulting from land 

clearing, grading, and excavation operations at exploration and production sites under various 

conditions of location, climate and slope. 

D. Water withdrawals 

At the scale of a single well or multiple wells on a single pad, 2-6 million gallons of water must 

be acquired to facilitate the drilling and completion of each well. The amount varies based 

primarily as a function of the length of the drilled lateral. To support MSGD, water can be 

extracted from surface or groundwater sources (including non-potable sources, see Section G), or 

even purchased from existing treatment plants if excess capacity exists. While 2-6 million 

gallons is a large volume of water, it is important to keep it in context relative to other 

withdrawals and supplies of water in the state. It was estimated by USGS that in the year 2000, 

Allegany and Garrett County withdrew on average 48.9 and 9.6 million gallons per day (MGD), 

respectively, from all surface water and groundwater sources. Over the course of an entire year, 

this works out to a combined volume of about 21.4 billion gallons of water. Thus, the combined 

annual withdrawals by these two counties alone would be equivalent to the amount of water 

required to develop about 3,500 Marcellus shale gas wells in the state. 

There are very long gage records available from USGS for most of the major rivers that could be 

used to support MSGD in western Maryland. We computed the mean annual discharge in 

western Maryland’s three largest headwater rivers (North Branch Potomac River near Steyer, 

Youghiogheny River at Friendsville, and Savage River below Savage River Dam) based on these 

records as part of a preliminary analysis of supply and obtained values of 112, 413, and 110 

MGD, respectively. The combined long-term average discharge in these three rivers is 635 

MGD—producing a volume of water on an average day that is more than 100 times larger than 

the water requirement to develop a single Marcellus shale gas well. However, it must be noted 

that the average discharge of water in these rivers varies dramatically throughout the year: in the 

Youghiogheny, for example, the long-term mean daily discharge in March (while normally 

swelled by spring snowmelt) is 769 MGD based on 71 years of data (1941-2011), although in 

September the long-term mean discharge is only about 22% as great (172 MGD). During low 

flow periods, as in drought years, flows in all of these rivers can become critical low. For 

example, in the Youghiogheny, the annual seven-day minimum flow was 18.7 MGD in 

September of 1972—illustrating that it is unlikely that flow conditions in even these major rivers 

can support withdrawals for MSGD at all times under all conditions. On the other hand, under 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-16 

average conditions and particularly at the higher discharges normally reached during the spring 

of the year, the data suggest that there may be adequate supplies provided by western Maryland’s 

major rivers as source water for MSGD. 

With respect to groundwater sources, in Chapter 1 we summarized the available information on 

western Maryland’s principal aquifers from the perspective of identification of aquifers and 

flowpaths as part of the drilling and hazard assessment processes. Much of that information is 

clearly relevant to identifying sources of groundwater that could be used for HVHF. On the 

Appalachian Plateau in Garrett County and western Allegany County, water yields of wells 

completed in Pennsylvanian age sandstone formations (the principal aquifers) reportedly range 

from 20 to 430 gallons per minute. In the Valley & Ridge west of the Great Valley, Ordovician 

to Devonian age sandstones are considered the principal aquifers, but wells completed in these 

formations commonly yield less than 120 gallons per minute; wells in limestone formations of 

late Silurian through early Devonian age may locally yield as much as 100 gallons per minute 

where these rocks are fractured (Trapp, Jr. and Horn 1997). These individual well yields (0.03 – 

0.6 MGD) are certainly high enough to suggest that western Maryland’s groundwater resource 

could potentially be exploited to support HVHF, but research would be needed to assess whether 

such development would likely cause the safe yield of these aquifers to be exceeded. We can 

envision that groundwater could play a role in supplying hydraulic fracturing operations during 

dry summer periods when water levels in major rivers and reservoirs are too low to permit 

surface withdrawals, or cases where a particular well pad (1) is located an excessive distance 

from a permitted surface water supply location; or (2) is not efficiently served by public roads 

that enable trucking of water. A centralized water well field (with suitable impoundment) could 

also potentially be used to supply (via buried pipeline) a group of multi-well pads that were part 

of a clustered development (see Chapter 1), with the caveat that the water wells would need to be 

sited so as to observe recommended setbacks. In the four eastern states (with similar 

hydrogeologic settings) that we reviewed, we found no evidence of extensive groundwater 

resource development to support MSGD19—presumably due to limited supplies, low well yields, 

and high costs (compared to the surface water alternative). Use of groundwater (in some cases 

drawn from saline aquifers) has supported shale gas development in some western states and 

western Canada (King 2012), but the far greater supply of surface water at lower cost suggests 

that it is highly unlikely that MSGD in Maryland would be primarily supported by available 

groundwater resources. 

In Maryland, both surface and groundwater withdrawals are regulated by MDE.20 Permit 

approval requires that the applicant provide satisfactory proof that the proposed withdrawal of 

water is reasonable and the impacts on the water resource and other users are acceptable. Further, 

the proposed use must be consistent with local planning and zoning requirements and the county 

water and sewer plan. Additional permitting documentation is required for requests for 

withdrawals in excess of 10,000 gallons per day, and public notification may be required. 

 

19 Recent data provided by SRBC to MDE indicates that Marcellus operators in Pennsylvania have obtained permits 

to supply 4% of their total water needs from groundwater sources computed by averaging over the entire basin 

(John Grace, MDE, personal communication, February 15, 2013). 20 COMAR 26.17.06 and COMAR 26-17.07 Details are available at: 

http://www.mde.maryland.gov/programs/Water/Water_Supply/Documents/www.mde.state.md.us/assets/document

/permit/2008PermitGuide/WMA/3.15.pdf 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-17 

Determining that a proposed withdrawal of water is “reasonable” can be done in several ways. 

In Maryland, the “Criteria for Approval of Water Appropriation or Use Permits”21, provides 

narrative regarding reasonableness, including a consideration of: (a) the purpose of the use; (b) 

the suitability of the use to the watercourse, lake or aquifer; (c) the extent and the amount of 

harm it may cause; (d) the practicality of avoiding the harm by adjusting the proposed use or 

method of use of the applicant or another permittee; (e) the practicality of adjusting the quantity 

of water used by each permittee; (f) aggregate changes and cumulative impact that this and 

future appropriations in an area may have on the waters of the state; (g) the contribution that the 

proposed appropriation may make to future degradation of the waters of the state; and (h) 

whether the proposed appropriation or use is located within a water management strategy area. 

For surface water sources, approved withdrawals are “conditioned on the maintenance, by the 

permittee, of a required minimum flow past the point of appropriation to protect other users of 

the water and to protect flora and fauna within the watercourse.22” The most common required 

minimum flow is typically set at the lowest 7 day average in the past 10 years (Q7-10). The Q7-

10 is specific to each source water and can be difficult to determine for streams without gages. 

Within Maryland, the required minimum flow is not always the Q7-10. In other states, 

withdrawals are often allowed up to a specific restricted flow point, for example, when the flow 

is less than 20% of the average daily flow. For gaged streams, average daily flow is easily 

determined; however, for ungaged streams, a reference gage approach using USGS regression 

tools is required. Significant uncertainty is often observed in such predictions (Murphy et al. 

2012, Razavi and Coulibaly 2012, Shu and Ouarda 2012). A comparison of the use of different 

methods for flow prediction using Maryland-specific historical gage data will provide a clear 

assessment of the most appropriate method for flow prediction in ungaged streams in the state. 

We are confident that there are adequate long-term and site-specific data for a sufficient number 

of gaged watersheds to support a rigorous analysis of stream discharges in western Maryland 

watersheds to inform an analysis of minimum required flow levels for streams that might support 

MSGD water withdrawals in the region. While we have not done such a quantitative analysis as 

part of our review of best practices, our experience in Maryland watersheds as well as review of 

other areas that have completed such analysis, suggest that in western Maryland, water 

withdrawals for proposed MSGD will need to occur solely from the region’s large rivers (and 

perhaps from one or more reservoirs). Small streams (1) have significant existing withdrawals 

for drinking water; (2) have small catchment areas and discharges under most conditions; (3) are 

very unlikely to have excess flow capacity for new permitted withdrawals; and (4) can be readily 

dewatered. 

Determining that the “impacts on the water resource and other users are acceptable” can be even 

more challenging than determining minimum required flows for streams. Multiple withdrawals 

within a basin can have a cumulative effect that must be considered in overall basin-level 

analysis. One method is to require the permitee to assess the cumulative net withdrawals upgradient of the proposed new withdrawal, and to consider cumulative impacts in the permit 

review process as is commonly done by basin commissions (SRBC 2012). Extensive review and 

analysis of watersheds in Pennsylvania has been undertaken to review and update requirements 

 

21 COMAR 26.17.06.05. http://www.dsd.state.md.us/comar/getfile.aspx?file=26.17.06.05.htm 

22 COMAR 26.17.06.05 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-18 

related to water withdrawals as shale gas drilling has expanded throughout the Susquehanna and 

Ohio River basins. Several critical reviews have been completed that should be considered as 

Maryland decides how to update water withdrawal permitting processes to consider the 

temporally and spatially distributed withdrawals typical of this industry. For example, the TNC 

Ecosystem Flows Study (TNC 2010) was a collaboration between The Nature Conservancy 

(TNC), the Susquehanna River Basin Commission (SRBC) and the United States Army Corps of 

Engineers (USACE). This study focused specifically on the Susquehanna River and its 

tributaries; however, the approach and general conclusions provide important information for 

MDE in assessing ecosystem considerations for streamflow and the role of this component in 

water withdrawal permitting for shale gas development. 

Recently, as part of proposed changes to the Low Flow Protection Policy of SRBC, MDE 

expressed concerns regarding the use of a fixed ‘de minimus’ threshold for headwater 

watersheds and highly sensitive watersheds since this ‘de minimus’ characterization is not used 

in Maryland statute (Kasraei 2012). As MDE notes in their response to SRBC, “it may not be 

feasible to appropriately quantify the flow regimes of certain ungaged smaller systems due to 

lack of relevant data” and other site specific conditions. As discussed above, the difficulty in 

assessing the impacts of water withdrawals with insufficient gaging data is well known (Murphy 

et al. 2012, Razavi and Coulibaly 2012, Shu and Ouarda 2012) and we strongly recommend that 

water withdrawals for MSGD be encouraged from larger rivers (and perhaps existing reservoirs). 

MSGD should totally avoid small headwater streams and watersheds out of concern for 

dewatering of these sensitive systems. Specific rather than generic minimum flow values should 

be established for these creek and stream systems, and seasonal water conditions should also be 

evaluated in the process. 

Timing of water withdrawals is also critical, with low flow conditions typically occurring 

seasonally. Storage and water transport from storage will be necessary to enable continued 

operations during the dry periods when withdrawals are likely to be limited. The size and number 

of any centralized water impoundments and pipelines constructed to support industry operations 

is often predicated on the stability of water supply. When water supplies are restricted for more 

of the year, gas development operations will either be restricted or larger and more 

impoundments will be required to enable continuous operations. Details of multiple uses for a 

single permitted withdrawals and of the plans to construct impoundments and pipelines are often 

contained within the water management plan required for shale gas development in 

Pennsylvania. These plans require identification of the water source at the time of drill permit 

application and lead to more comprehensive water sourcing plans for multi-well and multi-pad 

development. Multiple drilling companies within a single region may present overlapping plans 

with little coordination on water withdrawals. A regional multi-operator approach to water 

provision for shale gas operation would likely reduce the number of impoundments and 

withdrawal locations and enable smaller facilities, while still providing adequate and stable water 

supplies. Water management plans, in addition to water withdrawal permits, should be required 

for all drilling activities to ensure that development activities incorporate water resource 

planning. Coordinated multi-operational water provisioning should be planned to reduce the 

disturbances associated with impoundments and water withdrawals. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-19 

E. Comprehensive basin-scale water management planning 

Comprehensive basin-scale water management involves consideration of all uses and all 

activities associated with water within a watershed, often at the hydrologic unit code (HUC) 

level of 1 (i.e., HUC 2). This level is typically hundreds of thousands of square miles and 

usually involves multiple states. HUC 2 watersheds are often managed through interstate 

compacts. Maryland participates in several basin commissions (e.g., SRBC) and the Interstate 

Commission on the Potomac River Basin (ICPRB). No basin commissions exist in the most 

western part of the state where shale gas is found, however. Figure 4-4 shows the extent of 

relevant basins in Maryland. 

A portion of western Maryland within Garrett County is part of the Ohio River Basin (part of the 

larger Mississippi River Basin). The Ohio River Basin Commission was founded in 1981; 

however, the organization no longer operates, and it does not assert authority over water 

withdrawals within the basin. The Ohio River Valley Water Sanitation Commission 

(ORSANCO) is an interstate commission (established in 1948) charged with management of 

water quality in the Ohio River and its tributaries. ORSANCO does not have regulatory 

authority over issues of water quantity. The USACE Pittsburgh District has authority for the 

Youghiogheny Reservoir, a flood control and recreational reservoir that begins in Maryland and 

continues into southwestern Pennsylvania. Several groups have recommended the creation of an 

Ohio River Basin Commission that would manage water withdrawals to ensure water quality and 

protection of aquatic resources, especially during low flow conditions in the region (generally 

summer time) and ORSANCO is currently evaluating an expanded role that would incorporate 

water quantity authority. In general, the Youghiogheny River has been cleaner than the 

Monongahela River at the points of entry to Pennsylvania, providing important dilution of the 

main stem of the Monongahela River that travels north from West Virginia into Pennsylvania, 

terminating at its confluence with the Allegheny River to form the Ohio (at Pittsburgh, PA). 

Changes in the water quality within the Youghiogheny River would affect downstream water 

users in Pennsylvania. 

A major portion of Garrett County is part of the North Branch Potomac (0207002) watershed. 

Allegany County is located within the South and North Branch of the Potomac (0207001 and 

0207002) and the Cacapon-Town (0207003) subwatersheds. The USACE Baltimore District 

operates both Jennings Randolph Lake and Savage River Reservoir (both part of the North 

Branch of the Potomac River Basin). The ICPRB is the relevant watershed management 

commission for this part of the region; however, the ICPRB does not manage water withdrawal 

permitting within the basin. Ideally, comprehensive basin-scale planning and analysis would be 

used for water withdrawal permitting in western Maryland and elsewhere in the Potomac and 

Ohio River Basins. In the absence of interstate basin commissions with water permitting 

authority in this region, we recommend that MDE continue to take a comprehensive, basin-scale 

approach to all water withdrawals and to the assessment of water management plans submitted 

by any shale gas developers. MDE should also discuss the operational conditions of 

Youghiogheny Reservoir, Savage River Reservoir, and Jennings Randolph Lakes with USACE 

to evaluate these systems as potential sources of water for MSGD, particularly during high flow 

conditions when recreational and other uses would not be negatively impacted. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-20 

Figure 4-4. Major watersheds (HUC 8 and HUC 10) in western Maryland. 

F. Water storage and delivery 

Water must be staged on site at the well pad to support the hydraulic fracturing operation. 

During active development of the site, through drilling and the hydraulic fracturing operations, 

stormwater and rainfall will likely be collected for use in operations (see Section C), but this 

volume of water will not meet the high water needs for hydraulic fracturing. Well pad water 

management generally includes staging water tanks or constructing ponds to hold water, and 

using trucks to convey the 2-6 million gallons of water needed for the hydraulic fracturing. 

Alternative methods have been proposed and are currently being utilized that reduce or eliminate 

truck traffic and decrease the size of well pads. In the Pennsylvania state forests, freshwater is 

being moved from centralized storage facilities to active location(s) through the use of temporary 

piping. This practice significantly reduces the frequency of heavy hauling across state forest 

roads, minimizes the possibility of vehicular conflicts, and decreases air and dust pollution 

(PADCNR 2011). The piping of freshwater may involve above-ground or buried water pipeline 

networks, or a combination. Above-ground piping should be laid out in a manner to reduce 

aesthetic impacts and the potential for vandalism to the extent possible. Further, such piping 

should avoid interfering with existing infrastructure, including stormwater structures (e.g., 

culverts). Where applicable, buried piping should minimize additional earth disturbance and be 

co-located with natural gas pipelines, buried in the ditchline or vegetated berm, or trenched and 

buried beneath the running surface of an access road (PADCNR 2011). For example, in the 

Tiadaghton State Forest in north-central Pennsylvania, truck transport has been used to fill 

several constructed impoundments that provided gravity flow to an underground pipeline 

network that fed a cluster of well pads constructed in reasonably close proximity. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-21 

Freshwater delivered by either trucks or pipeline must also be staged near the operations. Open 

lined shallow impoundments (~15 MG capacity) are often constructed in Pennsylvania and used 

for this purpose (see Figure 1-5). The size and number of impoundments would need to be 

determined by the number of wells to be drilled and the number of pads within close proximity 

of a suitable impoundment location. Locations for these impoundments would be dictated by 

topography (i.e., suitable, reasonably flat locations where they can be constructed). Maryland 

has existing pond standards/specifications related to livestock watering, recreation, agricultural 

storage, and stormwater management (MDE 2000), but no specific standards exist for storage of 

water for oil and gas development. We recommend that freshwater impoundments be subject to 

the same standards regardless of water use. No impoundments constructed in Maryland should 

ever be used for storage of any wastewater (i.e., flowback or produced water), however. Nor 

should water released from temporary impoundments be discharged into any Maryland streams 

and rivers due to concerns for introduction of exotic species (e.g., golden algae) and impacts on 

water temperatures. As discussed in Section D above, coordinated planning for water needs 

across multiple operators and multiple well pads and development regions will reduce the 

number of impoundments needed to ensure reliable and sufficient water supply for this industry. 

G. Alternative water sourcing 

Wastewater is produced in a number of industrial activities that has potential as a source of water 

for hydraulic fracturing. The most frequently discussed alternate source is acid mine drainage 

(AMD) that is commonly discharged throughout the Marcellus shale region. Maryland Bureau of 

Mines has constructed and maintains 33 active and passive AMD facilities in Garrett and 

Allegany County with typical flows of 1 liter per second (L/s; 1 L/s = 0.023 MGD). Some of 

these facilities (or the mine pools from which the discharge is derived) could serve as alternate, 

non-potable water sources for MSGD. Among other known AMD sources is the outflow from 

the Hoffman Drainage Tunnel (HDT) near Clarysville, MD that typically discharges into 

Braddock Run (a tributary of Wills Creek) at a rate of about 7.3 MGD (recently reported range is 

7–30 MGD)—making this source a candidate to be evaluated as an alternate water source23. As 

discussed by one recent report, the use of AMD-impaired water or treated wastewater could have 

overall positive benefits on water quality through removal of these inputs from receiving streams 

(Lien and Manner 2010). We must note, however, that the cold water discharge of mine water 

from mine workings underlying Frostburg and the Upper Georges Creek Valley into Braddock 

Run via HDT appears to provide sustained baseflow in the receiving stream that exceeds by 

more than an order of magnitude the natural flow regime. HDT discharge also allows Braddock 

Run to support a brook trout population24, despite the fact that the discharge is obviously laden 

with ferric hydroxide—commonly known as “yellow-boy”. 

Nearby West Virginia and Pennsylvania have even more extensive acid mine drainage issues, 

with some outfalls in the tens of L/s range (Ziemkiewicz et al. 2003). Treatment costs are 

significant and treated water is discharged into surface waters (e.g., Hansen et al. 2010). 

Similarly, active coal mines and coal bed methane extraction activities generate high volumes of 

water during dewatering activities that are ongoing for the duration of the mining activity. These 

 

23 Unpublished analysis of field data by K.N. Eshleman and R.P. Morgan II for Lavale Sanitary Commission 

(September 4, 2002). 24 Jason Cessna (Appalachian Laboratory), personal communication (February 11, 2013) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-22 

waters are often salty, but considerably less salty than produced water from oil and gas activities. 

In many states (including Pennsylvania and West Virginia) coal bed methane produced water is 

permitted to discharge to surface water, and discharges can be considerable (32.3 million 

gallons/year in the Appalachian basin; USEPA 2010). Treatment is generally necessary for use 

of AMD-impaired waters in hydraulic fracturing, with removal of sulfate as a critical issue to 

prevent formation of barium sulfate precipitates that clog the well. Both abandoned and current 

coal mine discharges vary significantly from site to site, so site specific characterization and 

treatment would be needed for use of this water. Other industrial wastewaters may also have 

potential to be repurposed for shale gas development; however, this would require careful 

consideration of the impacts of wastewater diversion on in-stream flow in receiving waters. 

Further, the requirements for pre-treatment of different wastewaters may make this option 

impractical. 

Beyond water conditioning, issues of ownership and liability are a concern with use of impaired 

waters. As noted for Braddock Run, AMD-impaired water can even play an important ecological 

role as well. Drilling companies have expressed significant interest in use of AMD-impaired 

waters, but they do not want to be liable for cleanup of the continuing source once their shortterm need for water ends. An evaluation of the potential for use of coal mine drainage for 

hydraulic fracturing was completed by the Rand Corporation in late 2011(Curtright and Giglio 

2012). Conclusions included a need for new studies on sources of coal mine water that would be 

available for hydraulic fracturing, the evaluation of quantity and quality available across a 

region, and a collaborative approach among regulators, industry and other stakeholders to 

develop and analyze technical concepts and implementation mechanisms. Clearly, a best 

practice would be for Maryland to conduct a feasibility study on the potential use of known 

AMD-impaired waters in Garrett and Allegany County as source water for potential hydraulic 

fracturing operations. This is particularly important since as noted above, small headwater 

streams supply reservoirs extensively used for drinking water supply and are unlikely to have 

excess capacity for withdrawals. Water resources for extraction activities may be limited in areas 

targeted for development. As part of this study, Maryland should evaluate any regulatory 

limitations that would interfere with beneficial repurposing of mine water for hydraulic 

fracturing. 

H. Chemical delivery, storage on-site, and transfers 

Chemicals will need to be delivered and stored on site prior to drilling and completion 

operations. Some of these chemicals are hazardous and attention must be paid to their proper 

management. Closed storage tanks are necessary for all chemicals used on site. All tanks should 

be maintained in secondary containment to prevent contamination of the environment in the 

event of a spill. Adequate secondary containment should also be used in all areas where blending 

or transfer of chemicals takes place (NYSDEC 2011). Spill prevention, response and remediation 

plans (see Chapter 7 for details) should be developed and approved during well permitting and 

fully implemented when construction begins. Residual chemicals are not exempt wastes and 

must be managed based on their hazard classification. No blending of residual chemicals with 

production wastes is permitted under federal law. Operator training should be specifically 

required regarding the exempt vs. non-exempt wastes classification at the well pad, as this is an 

area of common confusion. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-23 

I. Identification of chemicals 

The composition of chemicals used on site must be clearly identified for safety and to enable 

remediation in the event of accidental releases. While some industry participants have been 

proactive in disclosure of chemical use, including chemical use in drill plans and spill 

prevention, response and remediation plans, this openness is not universal. Many, but not all, 

operators provide chemical disclosure through the web site, FracFocus (www.fracfocus.org ). 

Disclosures are permitted to include chemicals listed as proprietary if they represent a trade 

secret, as defined by applicable U.S. law. A best practice would be a requirement by the state of 

Maryland that operators provide full disclosure of chemicals used during completions. Detailed 

inventories including Material Data Safety Sheets (MSDS) should be required on site and on all 

truck manifests. To support preparations and training by first responders and well pad staff for 

any chemical emergencies, lists of chemicals to be used on site (plus appropriate toxicological 

data, chemical characterizations, MSDS, and spill clean-up procedures) should be included in 

permit applications. It must be kept in mind that MSDS may not contain information on specific 

chemical compounds, so it isn’t clear to us whether this information is sufficient to fully protect 

human health in the event of a spill or other emergency, however. 

Drillers report using fewer chemicals for MSGD than for other shale gas plays and the economic 

incentive to reduce chemical use even further is a strong motivator. To encourage advancements 

in “greener” (i.e., use of more benign chemicals) completions, Maryland should require 

completion plan alternatives during the permitting process. These recommendations are 

consistent with proposed practices for MSGD in New York (NYSDEC 2011). 

J. Drilling and drilling wastes 

Oil and gas development produces drilling wastes that must be temporarily stored on site, 

processed, and disposed of. Until very recently, storage was accomplished using lined open pits, 

but these can no longer be considered best practices. Closed-loop drilling systems that sit within 

secondary (and perhaps tertiary) containment are preferable to open pit systems and should be 

considered a best practice for Maryland. As with all waste handling and processing, adequate 

plans for spill mitigation must be in place in the event that an accidental release occurs. Since 

most drilling muds contain polymer additives, cuttings generally represent a mixture of native 

and amended materials that should be managed in accordance with their chemical characteristics. 

While oil and gas production wastes have a federal statutory exemption under RCRA and are, 

therefore, not categorized as hazardous wastes, they should be managed as wastes and their 

disposal should be based on their characteristics. Drill cuttings should be separated, recycled, or 

properly landfilled. Due to the potential for cuttings from shale formations to contain NORM, 

on-site disposal should not be permitted. Landfill disposal should be allowed when NORM levels 

indicate no significant enrichment beyond background levels. State action levels for NORM 

range from 5-30 picocuries per gram (pCi/g) of total radium and levels considered to represent 

‘uncontaminated’ materials are often set at twice the background level (NYSDEC 1999). As 

discussed in more detail in Section P, radioactivity monitoring at landfills is recommended to 

avoid unintentional comingling of radioactive wastes in conventional landfills. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-24 

K. On site management of produced waters and wastewaters 

Once drilling and completion have taken place, produced water will begin to be generated from 

the well during the flowback period, and later during the production phase. Flowback and 

produced water are not distinct wastewaters. The definition of flowback water is imprecise and 

can vary from well to well. It is sometimes operationally defined as water returning after the well 

completion for the first 10-14 days. It can also be defined as water returning after the completion 

and before the well head is installed for production (which can be sooner than ten days after 

completion). Because there is no consensus on when the transition from flowback to produced 

water occurs, and the water quality of both can vary significantly over time, flowback and 

produced water should not be treated as distinct classes of wastes. If distinction is desired, for 

example, because flowback may be higher quality (lower salts) and thus have alternative disposal 

options, the distinction should be made based on the quality of the water (i.e., a specific 

concentration of salts or specific chemicals such as strontium or NORM), not its classification as 

either flowback or produced water. 

Direct discharge of drilling wastewaters at the development sites is precluded by federal law25, 

which requires zero discharge from onshore gas wells (see Section C). Thus, all produced water 

must be collected and stored for either reuse on-site or shipment off-site for treatment or 

disposal. Treatment and disposal off-site are discussed in section L below. 

Significant quantities of water initially return to the surface. The volumes of produced water can 

vary considerably in different shale gas plays and even in different wells in the same formation. 

Typically 10-25% of the injected water returns to the surface as flowback during the preproduction phase (Hayes and Schroeder 2009). Marcellus formation wells have reported lower 

(10-15%) flowback rates, however (Hoffman 2010, Mantell 2011). Thus, on-site storage of 

significant volumes of produced water must be accommodated immediately after well 

completion. This has typically been accomplished in open impoundments where produced water 

is mixed with freshwater for makeup of the next well completion, however we strongly 

recommend that well pads sited in wet climates such as western Maryland utilize closed waste 

tanks for wastewater containment (with adequate secondary containment). Secondary 

containment (including dikes, liners, pads, curbs, sumps and other relevant structures) should be 

employed to minimize the potential for accidental releases of production wastes from these 

containment facilities. 

Despite the challenges associated with on-site management of large volumes of produced water, 

recycling this water for use in subsequent hydraulic fracturing operations either on the same site 

or at another site is an obvious best practice. Water produced in the flowback period can be 

stored on-site for use in a subsequent completion without any transport costs. Minimal treatment 

is necessary (e.g., settling) prior to dilution with additional freshwater for the next completion 

(Blauch 2010, Grottenthaler 2010). Recently Pennsylvania issued a general permit 

(WMGR1221) that covers treatment of produced water for subsequent reuse in hydraulic 

fracturing and encourages 100% recycling for water produced at well pads under development. It 

is not clear how such water is tracked or reported in Pennsylvania, but most large companies 

report nearly 100% recycling of early phase produced water (i.e., flowback) (Grottenthaler 2010, 

 

25 40 CFR §435.32. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-25 

Veil 2010). Maryland should include a very strong preference for on-site recycling in permitting 

shale gas development. 

Reuse in subsequent activities is the best management practice for later produced water as well, 

provided active new well development is taking place within the region and shipment distances 

are reasonably short. This is principally a logistical challenge, although trucking produced water 

increases both costs and the risks of spills during transit. While produced water is much saltier, 

its volume is quite low—often less than 200 gallons per million cubic feet (MMCF) of gas is 

reported in the Marcellus region (Mantell 2011). Thus, extensive dilution would occur in 

creating the next makeup water to achieve the necessary volumes for a completion. Many drillers 

have current goals of 100% recycling of all produced water, however this management option 

will not be economical if newer drilling pads are sited long distances from existing producing 

wells. This may not be a huge problem in Maryland, especially if MSGD can be sited in 

clustered industrial developments as discussed in Chapter 1. Produced water can also be treated 

off-site and returned for reuse at the same pad or to other well pads (as discussed in Section L 

below). This approach is common in Pennsylvania where centralized treatment plants offer 

partial treatment of produced water (removal of everything except monovalent ions: Na+

, Cl-, 

Br-

) with return of the highly saline water to the well pads for reuse. Maryland should include a 

strong preference for reuse of produced waters for subsequent shale gas activities, but should 

consider whether cross-state transfers of produced waters should be permitted for this purpose. 

Given western Maryland’s centralized location between two neighbor gas-producing states, this 

might be an efficient option. Permit applications should definitely include plans for produced 

water reuse and should specify which wells, within defined distances, will share water for reuse. 

L. Management of produced water (including recordkeeping, manifesting) 

As noted in Section K, there is no generally accepted definition of flowback and no legal 

definition that distinguishes between flowback and produced water. Best management practices 

should not attempt to distinguish based on these imprecise classifications but rather should refer 

to water quality characteristics if distinct handling is warranted. In most cases, management of 

the two wastewaters should be similar. Flowback may contain lower concentrations of salts, but 

higher concentrations of residual chemicals from the original hydraulic fracturing fluids. 

Produced waters generally become more concentrated in salts over production time; NORM may 

also increase with time in the produced water. 

Wastewaters produced during oil and gas development in the U.S. are considered non-hazardous 

by statutory exemption from RCRA26. As a non-hazardous waste, oil and gas production wastes 

are subject to different requirements for generation, transportation, treatment, storage and 

disposal. Maryland has been authorized by the USEPA to operate its hazardous waste regulatory 

program in lieu of the federal government, based in part on state regulations being at least as 

stringent as corresponding federal regulations. In some instances, Maryland’s regulations are 

more stringent than federal regulations as is allowed by federal law; Maryland has adopted the 

 

26 “Identification and Listing of Hazardous Waste; 40 CFR 261.4(b): Exclusions: solid wastes which are not 

hazardous wastes”. 40 CFR 261.4(b)(5) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-26 

exemption for exploration and production wastes associated with oil and gas development, 

however27. 

 

Some testing is generally undertaken to evaluate usability for recycling at treatment plants 

accepting these wastes to determine if they can be adequately treated by the methods employed 

at the plants. Wastes that do not meet certain criteria will not be accepted at certain treatment 

plants. Similarly, some testing is undertaken at deep well injection sites to determine if any 

treatment is necessary to avoid well clogging during injection. Results of this type of testing are 

used internally at these facilities. They are not reported to any regulatory agency, nor are they 

necessarily kept beyond the decision-making process. Trucks transporting any wastewater are 

required to carry manifests regarding their cargo, but are not required to be placarded as 

hazardous. Maryland should review its requirements for testing and manifesting of hazardous 

and non-hazardous waste to determine which regulatory structure applies to oil and gas produced 

wastes. 

Volumes of produced water from each well are generally reported on regular intervals to the 

state. These reports include the well number, volume of produced water, and the name and 

location of the waste operator to whom the water was taken (e.g., waste treatment facility, 

underground injection well site, etc.). If produced water was reused rather than disposed of, this 

is also noted, although in Pennsylvania the location of the reuse is not specified. These reports 

are tabulated in Pennsylvania and released to the public (via a web site) twice a year. It is not 

possible using Pennsylvania data to track water from extraction to use to reuse or ultimate 

disposal. A water balance for the industry cannot be completed because of insufficient detail in 

the water withdrawal plans (which withdrawals are for which wells) and insufficient detail on the 

reuse of flowback and produced water within multiple wells prior to ultimate disposal. In West 

Virginia, additional transportation records are required that might allow tracking of water from 

original withdrawal to final disposition, although the state does not undertake to evaluate water 

use and wastewater generation in this way. Maryland should require reporting of produced water 

volumes from every well, including the well location, the company providing transport of the 

produced water and the ultimate disposition of the waste, including the location of the 

subsequent well if the produced water was reused in hydraulic fracturing. 

In many areas of the country, road spreading of oil and gas brines is used for dust control or 

deicing. Generally due to higher levels of residual fracturing chemicals, this is not permitted for 

early produced water (i.e., flowback), but is commonly practiced with the low volume, high salt 

water that returns during the production phase. Spreading on roads within the oil and gas 

development region (often dirt roads created by the drilling companies), as well as in 

surrounding rural areas, is not uncommon. In Pennsylvania and West Virginia this activity is 

permitted for certain brines. Clearly, surface applications to roads or land will result in eventual 

runoff and entry of constituents present in the brine into the surface and ground water systems. 

Brines from the Marcellus formation contain very high concentrations of salt and are not 

appropriate for open discharge to the environment, particularly given western Maryland’s 

dependence on drinking water obtained from private groundwater wells and surface water 

obtained from headwater streams. Road spreading of the original produced water or any residual 

of its treatment should be prohibited. Several treatment facilities have suggested the creation of a 

 

27 COMAR 26.13.02.04-1A(5) 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-27 

salt product that would be suitable for road application through treatment of gas well brines. This 

should only be permitted if the created salt is low in bromide and iodide and replaces a 

conventional salt product already being used in the region. Underground injection is the common 

final disposal option for produced water in the U.S., and it is also appropriate for liquid residuals 

from treatment operations (e.g., highly concentrated brines). We discuss this option further in 

section N below, but it is unlikely to be used in Maryland. 

M. Treatment of produced water28

Produced water can be treated using a variety of chemical and physical processes to remove 

contaminants. Generally, radionuclides and multivalent metal ions are relatively easy to remove 

through coagulation, precipitation and filtration. Organics and oils can be removed through 

skimming or sorption. Monovalent ions (Na+

, Cl-, Br-) are particularly difficult to remove, 

requiring either membrane or thermal technologies that are energy-intensive. Concentrations of 

salt in produced water from the Marcellus formation in Pennsylvania and West Virginia are too 

high for membrane systems such as reverse osmosis; therefore, thermal technologies, including 

evaporation, multi-state flash distillation, and humidification-dehumidication methods, are the 

only viable treatment technology for the simple salts (Hayes 2009). Thermal desalination results 

in either an even more concentrated brine solution or a solid salt product as a residual. These 

residuals must be managed while the desalinated water can either be reused or discharged 

through a NPDES permit to surface water. 

Typically, partial treatment for recycling can be performed on-site (as described in section K), 

but all other treatment methods typically take place off-site. Produced water is picked up from a 

number of wells in tanker trucks on a regular schedule and taken to a centralized brine treatment 

plant. There are no permitted centralized brine treatment plants currently in Maryland. However, 

there are plants in West Virginia and Pennsylvania, and additional plants have been opening in 

response to additional produced water volumes requiring management. Two types of plants are 

operating in Pennsylvania. A few brine treatment plants that were operating before regulatory 

change to discharge standards on salt continue to operate without TDS limits for their discharge. 

These plants remove most contaminants except monovalent ions (Na+

, Cl-, Br-), and discharge 

the residual high salt brine to surface waters (creeks and rivers). However, these surface 

discharging plants no longer receive Marcellus formation produced water as the PA DEP 

requested that drillers stop using this disposal method. In Pennsylvania, new treatment plants 

must meet a discharge limit of 500 mg/L TDS. Maryland does not have a numerical criterion for 

TDS (or specific conductance—a related parameter) for in-stream water quality or for discharge 

permit limits. We do not recommend the use of brine treatment plants that partially treat 

produced water and discharge high concentrations of salt to the environment in Maryland. To 

avoid salt discharges into critical drinking water areas, prior to approving brine treatment plants, 

Maryland should enact a discharge permit limit for TDS and in-stream standards for TDS, 

chloride and bromide. Under no circumstances should Maryland allow discharge of partiallytreated brine or residuals from brine treatment facilities into the waters of the state. Further, 

development of brine treatment plants that recycle water to drillers should be discouraged in 

favor of on-site treatment by mobile units and immediate reuse as this decreases truck transport 

and associated impacts. 

 

28 An extensive review of treatment options is provided in Hammer et al. (2012). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-28 

Other brine treatment plants operating in Pennsylvania and West Virginia do not discharge 

wastewater to the environment. They treat produced water to remove metals and organics, and 

return the brine containing only monovalent ions to drilling companies for reuse. This is very 

similar to the on-site partial treatment for reuse discussed in Section K. Because this treatment 

requires additional transportation of the water (and adds to the associated impacts and risks), offsite treatment for reuse would be an even poorer option than on-site reuse in Maryland. 

However, if on-site treatment were deemed infeasible or off-site treatment facilities were closer 

than subsequent wells requiring water for reuse, such treatment plants could play a useful role. 

Materials removed from the water as sludges during treatment processes are typically dried and 

disposed of at landfills. Some of these treatment plants have plans to add additional treatment to 

desalinate water to acceptable discharge levels; however, such second stage treatment is not 

operational at most plants in Pennsylvania due to low demand for that type of extensive 

treatment. If the market for partially-treated water for reuse declines, these plants will likely offer 

full distillation services, but this will increase the treatment costs significantly. Distillation will 

produce highly concentrated brines or solid salts that will require subsequent management, either 

at deep well injection sites or landfills. The potential to create usable salt products from this 

process has been discussed, but technological and regulatory hurdles remain. Best management 

practices for residuals are discussed below. 

During the recent rapid expansion of development in the Marcellus formation in Pennsylvania, 

another management method for produced water was used. Produced water was sent to 

conventional wastewater treatment plants, classified by USEPA as publicly-owned treatment 

works (POTWs). These plants treat domestic sewage and are not designed to remove chemicals 

from oil and gas brines. However, relatively large wastewater volumes diluted the salts, and this 

method was considered acceptable as long as brine flows were low. In 2008 and 2009, many 

POTWs in Pennsylvania were accepting higher flows than their wastewater could adequately 

dilute. Concentrations of salts in the receiving waters rose unacceptably high in the fall of 2008. 

Concentrations of bromide, an ion with implications for drinking water treatment, rose as well. 

The PA DEP intervened in 2008 and 2009 to restrict use of POTWs for brine treatment. USEPA 

has also provided clarifications regarding the acceptance of oil and gas wastewaters and made 

substantial changes that required permit modifications29. In 2011, PA DEP requested that 

Marcellus wastewater not go to any surface-discharging POTWs without a TDS standard in their 

permit. Anecdotally, TDS and bromide levels have reportedly been lower in 2012 in some 

waterways (e.g., the Monongahela), but not in others (e.g., the Allegheny) following these 

changes30. In addition to Pennsylvania, Ohio is considering use of POTWs for brine treatment 

and disposal, and several lawsuits surrounding this situation are pending in that state. 

Following concerns regarding the use of POTWs, often without pretreatment of the produced 

water, the USEPA announced plans to develop pre-treatment requirements for oil and gas 

wastewaters being sent to POTWs (USEPA 2011). These rules are pending at this time. If 

promulgated, the rules would specify pre-treatment methods or water quality criteria for pre-

 

29 Ibid., 5 

30 To the best of our knowledge, these data have not been published in the peer-review literature, but the situation 

was widely covered in press accounts. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-29 

treated wastewater that would be sent to POTWs. These rules are unlikely to address all trace 

constituents of concern in produced water, as POTW treatment relies heavily on dilution to 

manage low concentration pollutants. For example, it is unclear if pre-treatment rules would 

consider bromide, a low concentration pollutant of concern only for downstream drinking water 

plants. 

Use of POTWs for dilution of produced water from oil and gas development is not a best 

management practice. Disposal practices that load salts (especially those containing chloride and 

bromide) to surface waters that are used for drinking water sources should not be permitted. This 

activity impedes treatment of water to provide water that is potable and safe for consumers. 

Higher chloride levels cause taste and odor problems in finished water. High bromide levels lead 

to increased formation of carcinogenic disinfectant by-products that can persist in the water to 

the point of consumption. Treatment of produced water by POTWs and other conventional 

wastewater treatment methods that do not remove salts should be prohibited in Maryland. 

 

A significant concern for any treatment method is the production and management of residuals. 

For most treatment systems, solids are removed into wet sludges, which can be disposed of in 

landfills as non-hazardous wastes. Treatment residuals created from exempt oil and gas produced 

waters are also exempt from federal laws related to hazardous waste, provided the exempt waste 

is not mixed with a non-exempt waste prior to the treatment process31. Maryland has not objected 

to the ‘derived from’ interpretation in RCRA that exempts residuals produced from exempt 

wastes. Treatment residuals will contain removed contaminants such as NORM, heavy metals, 

organic compounds, and salts, and these residuals should be evaluated for their constituents and 

managed accordingly. Since treatment residuals will generally have more concentrated levels of 

contaminants found in the original wastewater, deep well injection disposal is the preferred 

management strategy. 

N. Disposal of produced water or residual treatment wastes 

Most produced water, as well brine residuals from treatment of produced water, in the U.S. is 

disposed of through deep injection in Underground Injection Control (UIC) Class II wells 

specifically designed for disposal of brines and other fluids associated with oil and gas 

production, following requirements of the Safe Drinking Water Act of 1974 (Part C § 1421-

1426). The Marcellus region does not have an extensive deep well injection infrastructure. 

Pennsylvania has only a few UIC Class II wells that are mostly privately owned. West Virginia 

and Ohio have considerably more such facilities, including both private and commercial 

facilities. In general, trucking costs can make this disposal option prohibitively expensive for 

development in neighboring states. Concerns in Ohio regarding earthquakes associated with 

underground injection have also limited the new citing of commercial disposal wells. Maryland 

does not have a single UIC Class II disposal well. At present, disposal through deep well 

injection will require either trucking wastes to neighboring West Virginia or siting, permitting 

and drilling injection wells within Maryland. Maryland may prefer to develop UIC Class II 

injections wells to avoid long distance trucking of produced waters. However, these wells are 

commonly sited in played out areas of gas development, which Maryland does not have, or in 

areas that are also suited for gas storage, which Maryland is currently using for such purpose. 

 

31 58 FR 15284, 15285 (March 22, 1993) 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-30 

We anticipate that locations in Maryland for siting injection wells may be very limited. Review 

of injection well concerns in neighboring states and geological survey of Maryland subsurface 

formations should be undertaken prior to consideration of this activity in Maryland. Further, 

Maryland should review the relevant regulations surrounding development and use of UIC wells 

for produced water from shale gas development, and at the same time evaluate the capacity of 

nearby states to accept produced water or residual brine from treatment of produced water before 

permitting any development in the state. 

O. Reclamation and closure (decommissioning) 

In general, once production begins, interim reclamation of the site can be achieved through revegetation and modifications to the stormwater management systems as discussed earlier 

(Section C). This should normally take place within 60 days of the initiation of gas production, 

and the operator should submit a site restoration report to the state. Interim reclamation of the 

site after completion restores the disturbed land but allows continual access for collection of 

produced water, transport of gas (via gathering pipelines) and access for any future well 

reworking, if necessary. Road access must be maintained, but other areas of the site that were 

disturbed for heavy equipment needed during drilling and completion should be regraded and 

revegetated. All solid wastes should be disposed of using methods appropriate for the waste type, 

following state regulations. Residuals from gas drilling activities should be evaluated for their 

constituents to determine their status as hazardous wastes and managed accordingly. Water 

storage impoundments should be closed and these disturbed areas reclaimed. Pit liners should be 

removed and landfilled off-site. On-site disposal of residuals should not be permitted. 

Stormwater management for control of erosion and sedimentation should continue until the site 

is fully reclaimed. In Chapter 1 we discussed the rationale behind allowing development at 

multi-well pads to proceed more cautiously (especially as the first wells are drilled and the 

productive capacity of these wells is ascertained) and some of the ramifications for such a 

process from the standpoint of interim reclamation. We recommend that Maryland study very 

carefully how the development process at multi-well sites has taken place in other states 

(particularly Pennsylvania) and establish suitable regulations that balance the need to keep well 

pads completely operational for extended periods of time against the goal of ensuring that partial 

reclamation of these sites is not unduly delayed. 

Once production declines, wells are sometimes shut in for possible future development (i.e., 

refracking or drilling again from the same well pad location). A time limit should be established 

for wells in this status. If no additional development takes place within 12 months, site 

reclamation must begin unless an extension is issued by the state. Once no further well 

production is expected, final reclamation of the site should take place. As discussed in Chapter 3, 

this requires plugging the well to ensure isolation from the surface and near surface 

environments—a critical process in preventing water quality impacts from movement of residual 

gas or brine in the formation (as well as unintended losses of the gas resource). Permanent 

signage should be left in place to allow the well to be located if necessary in the future. 

Restoration plans should be developed in detail and submitted to the state. They should include 

stabilization and revegetation of all disturbed areas, including recontouring to reestablish the 

original topographic contours, use of native plant species and use of agency-approved seeds, and 

removal of all surface components of the facility (see Chapter 1). The goal of reclamation should 

normally be to return the developed area to native vegetation (or pre-disturbance vegetation in 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-31 

the case of agricultural land returning to production) and restore the original hydrologic 

conditions to the maximum extent possible. 

Improperly closed wells have led to significant environmental impacts in oil and gas states in the 

past (including Pennsylvania and West Virginia32,33) and thus should be avoided. Detailed, 

proscriptive methods for well closure should be developed through review of industry best 

management practices and other state regulations (see Chapter 3). Maryland should take a 

proactive approach to regulation in this area. With the implementation of best practices in well 

closure, Maryland should be able to avoid the problems that other states have experienced 

throughout their long oil and gas development histories. 

P. Naturally occurring radioactive materials (NORM) 

Shale gas formations often contain naturally-occurring radioactive materials (NORM) and drill 

cuttings and production brines can contain NORM. NORM should be assessed in all components 

of waste associated with gas production from shale. A 1999 study in New York State is a model 

for assessment of the industry for NORM concerns (NYSDEC 1999). Extensive on-site sampling 

and monitoring found NORM levels near background at most oil and gas production sites. 

Similar monitoring should be routine at MSGD sites to ensure adequate protection of workers 

and the environment. 

Oil and gas production wastes that exceed target levels should be reclassified as radioactive 

waste (RW) and not fall under the federal exemption of oil and gas production wastes34. 

Similarly, when drill cuttings and production wastes are treated or disposed of, residuals from 

these processes can become enriched in NORM (then called technologically-enhanced, naturallyoccurring radioactive materials or TENORM). This enrichment process should be monitored 

and, if necessary, residuals should be reclassified as radioactive waste (RW) to ensure they are 

tracked and protective disposal practices are used. All drilling wastes should be evaluated for the 

presence of NORM to ensure adequate disposal. Pennsylvania landfills have utilized radiation 

detection systems to ensure that radioactive wastes are not incorrectly comingled with 

conventional non-hazardous solid waste (PADEP 2012). Programs to monitor for radioactive 

waste at landfills should be adopted in states where shale gas drilling wastes may be sent to 

landfills. Maryland should adopt monitoring at solid waste disposal landfills for radioactivity. 

If NORM or TENORM waste associated with oil and gas production or waste treatment contains 

levels of radioactivity that would result in classification as low-level radioactive waste (LLRW), 

these residuals should be treated in accordance with LLRW regulations. LLRW generated in 

treatment of produced water from MSGD in Maryland would likely be disposed of outside of the 

state. The Appalachian States Low-Level Radioactive Waste Commission is an interstate agency 

established to assure interstate cooperation for the proper management and disposal of low-level 

 

32 Methane Emissions Project, Borough of Versailles, Pennsylvania. Available on the web at: 

http://www.netl.doe.gov/newsroom/versailles/Versailles%20Methane%20Emissions%20Project%20-

%20Final%20Report.pdf 33PA Department of Environmental Protection, Bureau of Oil and Gas Management, Stray Natural Gas Migration 

Associated with Oil and Gas Wells, available on the web at: 

http://www.dep.state.pa.us/dep/subject/advcoun/oil_gas/2009/Stray%20Gas%20Migration%20Cases.pdf 34 Federal Low Level Radioactive Waste Policy Act specifically exempts NORM. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-32 

radioactive wastes. The Commission identified Pennsylvania as the host state to receive and 

dispose of radioactive waste from the party states (Delaware, Pennsylvania, West Virginia and 

Maryland). Maryland producers of LLRW can also contract with out of state facilities through 

approval by other interstate commissions (e.g., Texas compact). 

Gas operations are typically short term and thus, build up of NORM at a given site is not 

expected; however, equipment is moved from site to site and could develop scale that 

incorporates NORM. Oil and gas production equipment should be assessed at regular intervals. 

Tanks on-site holding produced water could also develop precipitates with time that contain 

NORM. Regular inspections and cleaning of equipment and facilities that might be susceptible to 

the development of TENORM are recommended as part of best management practices for the 

on-site management of produced water. 

Q. Key recommendations 

3-A A best practice for Maryland would be establishment in regulation of 500 ft. and 2,000 ft. 

setbacks (measured from the well pad, not from the individual wellbores) for private 

wells and public system intakes (both surface and groundwater), respectively. 

3-B We support Maryland Environmental Code § 14-110.1 (H.B. 1123) and recommend predevelopment notification should be made to public and private drinking water well 

owners. 

3-C Pre-drilling groundwater testing should be required to be conducted by the operator and 

the results provided to MDE and to the well owner. Post-drilling testing is often at the 

discretion of the well owner, but a best management practice that would enable improved 

understanding of the potential for effects on groundwater would be to require postdrilling and completion testing by the operator for all wells within a pre-determined 

potentially affected region for a specified time period after completion of well 

construction activities. 

3-D Maryland might wish to consider ways of strengthening its anti-degradation policy to 

take account of the impacts of non-point source pollution that are a major threat to its 

high quality waters. One way that this might be accomplished would be by revising the 

WQS rules to require that any land development practices (e.g., forest management, 

MSGD, etc.) conducted in Tier II watersheds meet an anti-degradation standard. 

3-E Maryland needs to carefully review its stormwater regulations as they pertain to oil and 

gas extraction; we recommend oil and gas extraction sites be considered “hotspots.” 

Based on our review of stormwater management practices in other states, we recommend 

the use of both “active” and “passive” stormwater management: (1) the construction of 

properly bermed “zero-discharge” pads that effectively collect all water on a pad site and 

enable the reuse of this water during drilling and completion operations; and (2) 

construction of a below-grade lined pond adjacent to the bermed zero-discharge pad that 

could be used as a sump during active stormwater management phases and easily 

converted into a retention pond prior to a passive phase. 

3-F Post-construction inspections of stormwater structures should occur prior to well drilling 

and completion. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

4-33 

3-G There are very long gage records available from USGS for most of the major western 

Maryland rivers (Youghiogheny, Casselman, Savage, Potomac, Georges Creek) that 

could possibly be used to support MSGD; data for these and other gaged systems can be 

used to inform a quantitative analysis of acceptable water withdrawals for MSGD. This 

analysis is much more difficult for smaller streams and rivers due to data limitations, 

although we believe that such an analysis should be done. Our experience in Maryland 

watersheds as well as review of other areas that have completed such analysis, suggest 

that in western Maryland, water withdrawals for proposed MSGD would need to occur 

solely from the region’s large rivers (and perhaps from one or more reservoirs). Small 

streams (1) have significant existing withdrawals for drinking water; (2) have small 

catchment areas and discharges under most conditions; (3) are very unlikely to have 

excess flow capacity for new permitted withdrawals; and (4) can be readily dewatered. 

Water may need to be temporarily stored in centralized freshwater impoundments 

specifically constructed for this purpose, but such impoundments should never be 

allowed to receive or store any wastewaters. 

3-H To support preparations and training by first responders and well pad staff for any 

chemical emergencies, lists of chemicals to be used on site (plus appropriate 

toxicological data, chemical characterizations, MSDS, and spill clean-up procedures) 

should be included in permit applications. 

3-I Closed-loop drilling systems that sit within secondary (and perhaps tertiary) containment 

are preferable to open pit systems and should be considered a best practice for Maryland. 

3-J Maryland should include a very strong preference for on-site recycling of wastewaters in 

permitting of shale gas development. Under no circumstances should Maryland allow 

discharge of untreated brine, partially-treated brine, or residuals from brine treatment 

facilities, into the waters of the state. Development of brine treatment plants that recycle 

water to drillers should be discouraged in favor of on-site treatment by mobile units and 

immediate reuse as this decreases truck transport and associated impacts. 

3-K Maryland should review the relevant regulations surrounding development and use of 

underground injection wells for produced water from shale gas development and, at the 

same time, evaluate the capacity of nearby states to accept produced water or residual 

brine from treatment of produced water before permitting any development in the state. 

R. Literature cited 

Blauch, M. E. 2010. Developing effective and environmentally suitable fracturing fluids using hydraulic 

fracturing flowback waters. SPE Unconventional Gas Conference, Pittsburgh PA, Society of 

Petroleum Engineers. 

Boyer, E. W., et al. 2011. The Impact of Marcellus Gas Drilling on Rural Drinking Water Supplies, 

Pennsylvania State University. 

Castro, M. S., et al. 2001. Water Quality Assessment of the Piney Creek Reservoir and Watershed in 

Western Maryland. A. L. University of Maryland Center for Environmental Sciences, Report for 

Maryland Department of Natural Resources. 

Curtright, A. E., and K. Giglio. 2012. Coal Mine Drainage for Marcellus Shale Natural Gas Extraction. 

Pittsburgh PA, Rand Corporation. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-34 

USEPA. 2001. Industrial Surface Impoundments in the United States. Washington DC, U.S. 

Environmental Protection Agency. 

USEPA. 2010. Coalbed Methane Extraction: Detailed Study Report. Washington DC, U.S. 

Environmental Protection Agency. 

USEPA. 2011. Fact Sheet: EPA Initiates rulemaking to set discharge standards for wastewater from shale 

gas extraction. U.S. Environmental Protection Agency. 

http://water.epa.gov/scitech/wastetech/guide/upload/shalereporterfactsheet.pdf. 

Grottenthaler, D. 2010. Cabot gas well treated with 100% reused frac fluid. DUG 2010, Pittsburgh PA. 

Hammer, R., et al. 2012. In Fracking's Wake: New Rules are Needed to Protect Our Health and 

Environment from Contaminated Wastewater. New York, New York, Natural Resources Defense 

Council. 

Hansen, E., et al. 2010. The Benefits of Acid Mine Drainage Remediation on the North Branch Potomac 

River. DownstreamStrategies. Morgantown WV, Maryland State Water Quality Advisory 

Committee. 

Hayes, T. 2009. Sampling and Analysis of Water Streams Associated with the Development of Marcellus 

Shale Gas. Prepared for Marcellus Shale Coalition. 

Hayes, T., and C. Schroeder. 2009. Barnett and Appalachian Shale Water Management and Reuse 

Technologies. DOE-NETL Oil Technology E&P. Environmental Projects Review, Morgantown, 

WV. 

Hoffman, J. 2010. Susquehanna River Basin Commisssion Natural Gas Development. Presentation to 

public at Marywood University. 

Kasraei, S. 2012. Letter to Ms. Paula Ballaraon and Mr. John Balay, Susquehanna River Basin 

Commission. MDE. Baltimore, MD. 

King, G. E. 2012. Estimating frac risk and improving frac performance in unconventional gas and oil 

wells (paper SPE 152596). Hydraulic Fracturing Conference, The Woodlands, TX (February 

2012). 

Lien, A. M., and W.J. Manner. 2010. The Marcellus shale: resources for stakeholders in the Upper 

Delaware watershed region. Pinchot Institute for Conservation. 

Mantell, M. E. 2011. Produced Water Reuse and Recycling Challenges and Opportunities Across Major 

Shale Plays. EPA Hydraulic Fracturing Study Technical Workshop #4: Water Resources 

Management, Chesapeake Energy. 

MDE. 2000. Conservation Practice Standard for POND, USDA Natural Resources Conservation Service. 

MDE. 2009. Maryland Stormwater Design Manual, Volumes I and II. Baltimore MD: Maryland 

Department of the Environment. 

MDE. 2011. Maryland Standards and Specifications for Soil Erosion and Sediment Control. Baltimore, 

MD: Maryland Department of the Environment. 

MDE. 2012. Maryland Model Erosion and Sediment Control Ordinance. Baltimore, MD: Maryland 

Department of the Environment. 

Marcellus Shale Advisory Commission. 2011. [Pennsylvania] Governor's Marcellus Shale Advisory 

Commission Report . 

Murphy, J., et al. 2012. Predicting Ecological Flow Regime at Ungaged Sites: A comparision of methods. 

River Research and Applications. 

NYSDEC. 1999. An Investigation of Naturally-Occurring Radioactive Materials (NORM) in Oil and Gas 

Wells in New York State. Albany, NY: New York State Department of Environmental 

Conservation. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

PADEP. 2003. Evitts Creek Source Water Assessment, Pennsylvania Department of Environmental 

Protection: 2. 
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PADEP. 2012. Monitoring for Radioactive Materials in Solid Waste. Retrieved November 27, 2012, from 

http://www.dep.state.pa.us/brp/Radiation_Control_Division/SolidWasteMonitoring/SolidWasteR

adMonitoring.htm. 

Razavi, T. and P. Coulibaly. 2012. Streamflow prediction in ungauged basins: review of regionalization 

methods. Journal of Hydrologic Engineering. 

Shu, C., and T. B. Ouarda. 2012. Improved methods for daily streamflow estimates at ungauged sites. 

Water Resources Research 48 (W02523), doi: 10.1029/2011WR011501. 

SRBC. 2012. Natural Gas Shales and Natural Gas Well Development. Retrieved December 4, 2012, from 

http://www.srbc.net/programs/projreviewnaturalgas.htm. 

State of Oregon Department of Environmental Quality. 2010. Issue Paper: Evaluating the Antidegradation 

Policy as a Means to Reduce Nonpoint Sources of Toxic Pollutants to Oregon Waters (Final 

Draft); prepared by D. Sturdevant and J. Wigal. 

TNC. 2010. Ecosystem Flow Recommendations for the Susquehanna River Basin: Report to the 

Susquehanna River Basin Commission and the U.S. Army Corps of Engineers. The Nature 

Conservancy, M. DePhilip and T. Moberg. Harrisburg, PA. 

Veil, J. A. 2010. Water Management Technologies Used by Marcellus Shale Gas Producers. Argonne, IL, 

U.S. Department of Energy. National Energy Technology Laboratory. 

Ziemkiewicz, P., et al. 2003. Long-term performance of passive acid mine drainage treatment systems. 

Mine Water and the Environment 22:118-129. 

 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

5-1 

5. Protecting terrestrial habitat and wildlife1

Despite high levels of development in many areas of the state, western Maryland (Allegany and 

Garrett County) remains a largely intact landscape relative to other regions of the eastern United 

States2. The dominant land cover type of the Appalachian mountains of western Maryland is 

forest (>75%; Figure 5-1), including extensive areas of forest interior habitat (Figure 5-2). The 

total extent of habitat loss potentially caused by Marcellus Shale gas development is anticipated 

to be small relative to other forms of land conversion in the state (e.g., urban/suburban 

development, surface mining for bituminous coal), but not insignificant (e.g., Drohan et al. 

2012). We estimate that with careful planning new disturbances could be less than 1-2% of the 

land surface (see Chapter 1). Nevertheless, not all forests are of equal value, and rare or sensitive 

forest habitat should be avoided. Beyond the direct loss of habitat, many species in western 

Maryland are potentially sensitive to new construction that reduces the amount of core and 

connected habitat, creates opportunities for direct exposure to toxic contaminants, provides 

opportunities for biological invasions, or alters the soundscapes and night-time lightscapes. 

Eighty-seven animal species and 117 species of plants are currently listed as rare, threatened, or 

endangered within Maryland's Marcellus Shale region (Appendix 5A). Many of the 

recommendations in this chapter are aimed at minimizing the fragmentation of the forested 

landscape with special emphasis on protecting irreplaceable habitats and imperiled terrestrial 

biota. Forest protection is also protective of downstream aquatic resources (Chapter 6), and 

practices such as the preservation of forested riparian buffer are important to both terrestrial and 

aquatic resources. In general, no-net-loss of forest is a goal consistent with the state's overall 

resource stewardship and a useful guiding principle for shale gas development in western 

Maryland. 

A. Well pad spacing and siting 

Any surface disturbance that punctures intact forest provides an impact that is greater than the 

amount of forest loss alone (Harris 1984). For example, a 1% net loss of total forest, as was 

observed for the conterminous United States from 2001 to 2006, can translate to net losses of as 

much as 10% of forest interior area (Ritters and Wickham 2012). A tentative pattern has been 

reported for Marcellus shale sites in Pennsylvania that interior forest loss is approximately twice 

that of the overall forest loss (Slonecker et al. 2012). Another recent study in Pennsylvania found 

that Marcellus well pads and associated infrastructure (roads, water impoundments, and 

pipelines) required approximately 9 acres per well pad with an additional 21 acres of indirect 

edge effects3

. Loss of interior habitat, defined as areas of forest at least 100 m (328 ft) from the 

 

1

 Chapter co-authors: Todd R. Lookingbill, Ph.D. (Department Geography and the Environment, University of 

Richmond, Richmond, VA, 23173); and Andrew J. Elmore, Ph.D. (Appalachian Laboratory, University of 

Maryland Center for Environmental Science, Frostburg, MD 21532) 2

 Saylor, K.L. 2008. Land Cover Trends Project: Central Appalachians. U.S. Department of the Interior, U.S. 

Geological Survey, Washington, DC, USA, available at http://landcovertrends .usgs.gov/east/eco69Report.html. 3

 Johnson, N. 2010. Pennsylvania energy impacts assessment, Report 1: Marcellus Shale Natural Gas and Wind, The 

Nature Conservancy, Pennsylvania Chapter, and Pennsylvania Audubon, 

http://www.nature.org/wherewework/northamerica/states/pennsylvania/news/news3511.html.
K.N. Eshle

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5-4 

lands. Such efforts must be conservation oriented rather than preservation oriented in nature to be 

able to sustain native plant communities in a developed landscape.6

Unfortunately, Allegany and Garrett County are currently exempt from the Maryland FCA 

because of their high percentages of forest land-cover and perceived lack of threat from 

residential development relative to the rest of the state. Marcellus shale gas development 

represents a new land-cover change process on these landscapes. Therefore, Maryland should 

consider adopting a no-net-loss of forest approach to Marcellus Shale gas development. The 

primary mechanism for implementing this approach would be through the requirement of forest 

plantings elsewhere in Maryland to mitigate any well pad or related MSGD that remove forest 

from the landscape. The requirement might be best implemented by expanding the FCA to 

include the two counties of western Maryland. Regardless of the mechanism, the siting of 

mitigation plantings should consider regional conservation goals and water quality improvement 

potential. Clearly such an approach would help to incentivize the siting of well pads and other 

infrastructure on non-forest lands. 

Following the examples of Colorado and as proposed in Pennsylvania, Maryland might consider 

well-pad permitting as part of a comprehensive gas development planning process (described in 

Chapter 1). New York State law allows the environmental impact of more than one project to be 

considered at the same time (Strong 2008). A small project may not have a negative impact on 

habitat alone, but when considered in the context of nearby or related projects, the negative 

impact may be significant. With respect to terrestrial habitat, a comprehensive gas development 

plan could help channel development into areas with greater amounts of existing disturbance and 

avoid areas with intact forests (especially forest interior habitat and other high priority 

conservation areas). Efforts in this area would greatly improve Maryland’s ability to address 

cumulative impacts of MSGD which are likely to be significant without proper regulation. 

B. Impoundments 

Direct exposure to contaminated water stored on-site and during transportation on- and off-site 

can come from tank leaks and spills during tank transfers, and is one of the biggest threats to 

wildlife from hydraulic fracturing operations (Thompson 2012). Although many of the chemicals 

contained in hydraulic fracturing fluids are potentially toxic to wildlife, there are few studies on 

the exposure effects of gas operations to animals. One recent study of farm animals in six states 

(Pennsylvania, New York, Ohio, Colorado, Texas, Louisiana) suggested increased mortality 

rates in livestock and companion animals (i.e., dogs and cats) living close to active gas-drilling 

operations (Oswald and Bamberger 2012), with several caveats associated with the lack of 

controls due to the case study aspect of the survey (Thompson 2012). Although chemicals can be 

volatized (e.g., by impoundment aerators) and misted into the air creating an inhalation exposure 

pathway, the most common source of toxicity exposure was likely via contaminated water. 

Pathways of exposure included, for example, spills of hydraulic fracturing fluids, tears in the 

liners of wastewater impoundments, and spreading of wastewater on roads to reduced dust and 

ice followed by animals licking their paws after crossing the roads (Table 5-1). Health impacts 

 

6

 Maryland No Net Loss of Forest Task Force Final Report and Recommendations. January 2009. 

http://www.dnr.maryland.gov/dnrnews/pdfs/NNLTFFINALREPORT1.pdf
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

5-5 

ranged from neurological to sudden death with the most common effects being reproductive. 

Animals affected include cows, horses, goats, llamas, chickens, dogs, cats, and koi. Because the 

movement of farm animals is confined they may experience higher cumulative exposure than 

wildlife with less restricted mobility. However, photographic evidence has been reported of dead 

and dying songbirds, deer, frogs, and salamanders (Oswald and Bamberger 2012). The lack of 

controlled dose-response studies is due in part to the lack of information on the specific 

chemicals used in the hydraulic fracturing. Additionally, substances that occur naturally in the 

shale may come to the surface as part of the process. These constituents are poorly quantified, 

but can be equally or more 

toxic than the hydraulic 

fracturing fluid. 

To limit the exposure of 

wildlife to toxic chemicals, 

impoundment ponds used to 

store flowback and produced 

wastewater should not be 

permitted in Maryland. 

Evaporation in wastewater 

impoundments can increase the 

concentration of some toxins, 

making them fatal traps to 

migratory birds and other 

wildlife that may try to use the 

ponds7

. In the State of New 

York's revised guidelines, 

watertight tanks are the 

preferred option to store 

flowback and produced water 

(NYSDEC 2011). Pennsylvania 

DCNR recommends the 

following steps to protect 

ecological resources from off-site spills: (1) use of double-wall tanks for the storage of chemicals 

and liquids; (2) wherever possible, chemicals and liquids should be stored inside storage trailers 

(PADCNR 2011). Closed storage tanks with secondary containment should be used for all 

storage of chemicals and produced waters, especially in areas with significant rainfall such as 

western Maryland (see Chapter 4). Where impoundments are used (e.g., for temporary storage of 

freshwater only) fencing of these water features and freeboard of several feet should be 

maintained. The construction of any impoundments should consider the increases in storm 

intensities that are projected as a consequence of the state's changing climate (Boicourt and 

Johnson 2010). Runoff and spill prevention, response and remediation plans should be a 

necessary part of the permitting process. Finally, to protect wildlife and downstream water 

quality, spraying of wastewater (flowback or produced water) on roads to minimize dust, for 

example, should not be permitted under any circumstances. 

 

7 Ramirez, P. 2009. Reserve Pit Management: Risks to Migratory Birds. U.S. Fish & Wildlife Service, Region 6, Environmental 

Contaminants Program, http://www.fws.gov/mountain-prairie/contaminants/documents/ReservePits.pdf 

Table 5-1. Case survey documenting impacts to farm animals 

living near gas drilling operations (Oswald and Bamberger 

2012). 

Source of exposure 

# of 

cases 

Hydraulic fracturing fluid spill from holding tank 2 

Drilling fluids overran well pad during blow out 1 

Storm water run-off from well pad to property 3 

Wastewater impoundment leak 1 

Wastewater impoundment allegedly compromised 1 

Wastewater spread on road 2 

Wastewater dumped on property 1 

Wastewater dumped into creek 3 

Wastewater impoundment not contained 3 

Well/spring water 17 

Pond/creek water 8 

Pipeline leak 1 

Compressor station malfunction 2 

Flaring of well 3 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 5 

5-6 

C. Riparian setbacks 

Forested riparian buffers enhance biodiversity by (1) providing foraging, nesting, brooding, 

thermal, and escape cover; (2) protecting sensitive habitats; and (3) maintaining landscape 

connectivity (Bentrup 2008). These terrestrial habitats also provide valuable buffer benefits to 

aquatic environments, for example, by shading streams to maintain favorable temperature 

(Moore et al. 2005). Despite strong evidence that forested riparian buffers are an important best 

management practice, the scientific basis for determining a specific width for the BMP depends 

on the overall rational for the buffer. Much of the scientific evidence (Table 5-2) supports the use 

of relatively large forest buffers when the intent is to preserve biological diversity (Bearer et al. 

in press). For example, herptiles [i.e., amphibians (e.g., frogs, toads, and salamanders) and 

reptiles (e.g., snakes, turtles, and terrapins)] exhibit life stages during which individuals will 

migrate great distances from streams and wetlands in search of new habitat (Grant et al. 2010). In 

a study of marbled salamanders, over 200 juvenile salamanders were captured at distances 

between 365 and 4,035 ft (median = 883 ft) from natal ponds (Gamble et al. 2006). Similarly, 

considerable work has been devoted to evaluating the typical dispersal distances of turtles, with 

most recommendations for forest buffer widths falling in the range of 500-1,000 ft (e.g., Bodie 

2001) which is intended to capture 95% of all migrating individuals. There is also abundant 

evidence that aquatic insects utilize riparian buffers during adult life stages (Bried and Ervin 

2006), indicating the unique nature of riparian forests as foraging habitat for rare, threatened and 

endangered bats (Lookingbill et al. 2010). 

Many riparian areas in western Maryland are currently forested (e.g., 75.8% of the land area 

within 300 ft of streams is forest). Any denuded riparian zones provide opportunities for 

reforestation as part of our recommended no-net-loss of forest policy. Riparian setbacks would 

help ensure that MSGD was designed to minimize harm to this critical terrestrial habitat. We 

recommend minimum setbacks of 300 ft from floodplains, wetlands, seeps, vernal pools, 

streams, or other surface water bodies (Figure 5-3). This distance is consistent with estimated 

requirements from the scientific literature for terrestrial species that use riparian areas as 

movement corridors and amphibians, turtles and other aquatic species that use the land for at 

least part of their life cycles (Table 5-2). The distance is also consistent with U.S. Department of 

Table 5-2. Representative list of studies providing evidence supporting different riparian 

setback widths.

Response tested Setback 

recommended 

Citation 

Neo-tropical bird activity 330 ft (Hodges and Krementz 1996) 

Dragonfly activity >530 ft (Bried and Ervin 2006) 

Turtle migration 910 ft (Burke and Gibbons 1995) 

Salamanders 330 ft (Crawford and Semlitsch 2007) 

Salamanders 890 ft (Gamble et al. 2006) 

Birds 660 ft (Perry et al. 2011) 

Freshwater reptiles 1,240 ft (Roe and Georges 2007) 

Salamanders 410 ft (Semlitsch 1998) 

Amphibians and reptiles 960 ft (Semlitsch and Bodie 2003) 

Wildlife 330 ft (Wanger 1999) 

Aquatic diversity 330 ft (Castelle et al. 1994) 

Amphibians and small mammals 330 ft (McComb et al. 1993) 
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5-8 

Program has developed a digital map known as BioNet (Biodiversity Conservation Network) that 

effectively prioritizes areas of the state for conservation of freshwater and terrestrial plants, 

animals, habitats, and landscapes. The purpose of the assessment was to provide decision support 

for species and land conservation programs including the guidance of compatible land uses and 

land management practices. These data represent the most up-to-date understanding of the spatial 

distribution of biotic resources in the state and guide the state’s overall biodiversity stewardship 

strategy. The criteria used within BioNet have a dual focus on the rarest species and habitats, as 

well as the habitats that concentrate the largest numbers of rare species and habitat. Thus, BioNet 

considers areas with: (1) only known occurrences of species and habitats; (2) globally rare 

species and habitats; (3) state rare species and habitats; (4) animals of greatest conservation need; 

(5) watch list plants and indicators of high quality habitats; (6) animal assemblages (e.g., colonial 

nesting waterbirds, forest interior species); (7) hotspots for rare species and habitats; (8) intact 

watersheds; and (9) wildlife corridors and concentration areas. These areas are prioritized into a 

five-tiered system: 

• Tier I – area is critically significant for biodiversity conservation 

• Tier II – area is extremely significant for biodiversity conservation 

• Tier III – area is highly significant for biodiversity conservation 

• Tier IV – area is moderately significant for biodiversity conservation 

• Tier V – area is significant for biodiversity conservation 

Areas identified include those that support the 204 state-listed species (Table 5A), rare and high 

quality plant and animal communities, high wildlife densities, and important habitats needed for 

wildlife migration and movements related to climate change. Tier I and Tier II sites represent 

locations that Maryland DNR has designated as “irreplaceable natural areas”8

. 

Consistent with Pennsylvania state forest policy, we recommend a no-disturbance setback within 

and 600 ft around any priority conservation area (Figure 5-4). Priority conservation areas should 

be defined using the best available science and designed so that no irreplaceable areas of unique 

habitat could be impacted by MSGD. Portions of the BioNet dataset, specifically irreplaceable 

natural areas (BioNet Tier I and II sites) and wildlands should initially be considered as priority 

conservation areas and receive the recommended 600 ft setback. BioNet data products should be 

kept up to date and publically available, so that potential MSGD operators have the information 

required to identify lands for their activities that would have the least impact on the natural 

resources of Maryland. The methods used to generate BioNet products should be published in 

the scientific literature. 

Caves were addressed in Chapter 1 while discussing potential complications arising during 

drilling, well casing and cementing; however, caves (including those subterranean voids that are 

man made) are also a terrestrial habitat of special concern. Western Maryland is home to two 

globally ranked species of bat that are critically imperiled in the state because of extreme rarity 

(Table 5-1). The Indiana bat (Myotis sodalis) is a federally listed endangered species in danger of 

extinction throughout significant portions of its range. However, even common species of cavedwelling bats are currently in a status of extreme flux due to the poorly understood white-nose 

 

8

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 K.N. Eshleman & A.J. Elmore (2013) Chapter 5 

5-10 

E. Noise and light 

Noise and light pollution associated with unconventional gas development have not been studied 

in depth, but increasing evidence suggests that these factors have significant effects on wild 

animals (Beier 2005, Pijanowski et al. 2011). More research on the topic is needed, particularly 

with respect to noise. Noise pollution can affect wildlife in at least two ways: (1) disruption of 

communication by masking acoustic signals (primarily an issue for birds, but may also affect 

amphibians and terrestrial mammals); and (2) reductions in abundance, distribution and density 

of species due to avoidance behavior (Patricelli and Blickley 2006, Barber et al. 2009). In a study 

of gas well operations in northwestern New Mexico, noise amplitude was amplified over 

baseline amplitudes up to distances of 3000 ft from a compressor (Francis et al. 2010). Nest 

occupancy was depressed for bird species within this affected area by an average of 5%. In a 

study of Wyoming sage-grouse, natural gas drilling and road noises were recorded and played at 

70 dB(f) in front of leks13 (Blickley et al. 2012). This sound pressure level is similar to what is 

measured 1300 ft from drilling rigs and main access roads in that landscape. After three years of 

study, intermittent noise from roads decreased male attendance at the leks by 73% relative to 

paired controls. Drilling noise decreased attendance by 29%. Another study on mule deer 

indicated significant decreases in populations in areas within close proximity to well pads due to 

avoidance behavior (Francis et al. 2010). 

The use of sound barrier walls around compressors can reduce the area affected by noise by up to 

70% and maintain occupancy and nest success rates at levels close to those expected in a 

landscape without compressor noise (Francis et al. 2010). New York State (NYSDEC 2011) and 

API (API 2011) have established techniques for evaluating and mitigating noise impacts of gas 

operations. Following these guidance documents and consistent with Chapter 9 we recommend 

that Maryland require as part of the permitting process: (1) maintaining a maximum distance 

between well pads and BioNet irreplaceable natural areas to reduce noise effects on these 

sensitive lands; (2) constructing artificial sound barriers where natural noise attenuation would 

be inadequate; (3) equipping all motors and engines with appropriate mufflers; and (4) avoiding 

construction and drilling operations during sensitive migrating and mating seasons.

All bats and many other mammals, amphibians, and birds are nocturnal. When subjected to 

artificial lighting at night, documented animal responses include altered forage and mating 

behavior that, depending on the species and circumstances, can lead to changes in survival and 

fecundity (e.g., Beier 2005). Bats, for example, use their limited vision to exploit low levels of 

light as they leave a roost and to avoid obstacles [such as the capture nets used by biologists that 

study bats (Wang et al. 2004)]. Notably, bats are known to avoid disorienting bright light. Bats 

are farsighted, suggesting they use light more often when it is further away and dim, and switch 

to echolocation for objects that are closer. When migrating, bats will use vision rather than 

echolocation, which helps to explain why they are known to fly into wind turbines (Johnson et al. 

2003). With song birds, artificial lighting has been shown to shift singing to earlier morning 

hours, alter mating success, and result in an earlier start of egg laying in spring (Miller 2006, 

Kempenaers et al. 2010). Artificial lighting alters foraging, reproductive, and defensive 

 

13 A lek is a gathering of males, of certain animal species, for the purposes of competitive mating display. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

5-11 

behaviors in amphibian species (Andrews et al. 2008). For example, frog calls are reduced under 

artificial lighting, which can reduce mating success and thus affect population dynamics (Baker 

and Richardson 2006). Artificial lighting near aquatic habitat can also become an attractive 

nuisance, attracting insects that subsequently die before finding new habitat. 

There are two sources of light that are commonly found at drill pad sites during MSGD: (1) 

artificial lighting, used to illuminate the site or transportation routes to and from, or between drill 

pad sites, and (2) flaring of unwanted or waste gas during well completion. Although the impact 

of artificial light in rural settings such as western Maryland is fairly well documented, relatively 

little has been recommended as BMPs by the various states for unconventional gas development. 

Some states have suggested flaring is the most egregious source of light. For example, 

Pennsylvania requires gas operators to provide a minimum of 10 days notice to the Forest 

District Manager when flaring activities are anticipated, but this requirement only pertains to 

Dark Sky Areas. The Forest District Manager is required to coordinate with drilling operators to 

reduce conflicts during special events on state lands that require dark skies (PADCNR 2011). 

Proposed rules in Colorado and BMPs recommended by API also mention light pollution (API 

2011), but only suggest considering light as a motivation for increasing setbacks from 

residences. Proposed rules in New York are the most protective of wildlife, requiring lighting 

used at well pads to shine downward during bird migration periods (April 1–June 1 and August 

15–October 15)(NYSDEC 2011). 

Additional best management practices available to Maryland include requiring: (1) diffuse 

downward pointing lighting at all times; (2) the use of low-pressure sodium lamps (most energy 

efficient) instead of high-pressure sodium 

or mercury lamps; (3) the use of UV 

filters; (4) reduced lighting to only 

locations and intensity needed; and (5) 

using green light rather than red or blue 

where possible. Green light and UV 

filtered light has been found to be less 

disorienting to migrating birds than is red 

or blue light (Wiltschko et al. 1993, Poot 

et al. 2008). Limiting the height of 

lighting columns (e.g., to a height less 

than 8 m) and directing light downward 

reduces the ecological impact of the light 

(Fure 2006). In some circumstances, 

outfitting sensors to lights that are 

activated when light is needed could be 

an effective means of reducing light 

levels on average. Flaring during the 

completion process should be minimized 

or eliminated, which will be required by USEPA starting in 2015 (Chapter 1). When we visited a 

drill pad site in West Virginia operated by Chesapeake Energy, we noted that lighting was 

mounted appropriately low and was covered with diffusing fabric, presumably to reduce glare 

and shadows. Each lamp was “capped” with a downward-reflecting shield, which might be 

effective at reducing light pollution of dark skies (Figure 5-5). We did not see these lamps in 

Lamp 

Figure 5-5. The authors observed lamps at this well pad in 

Brooke County, WV (operated by Chesapeake Energy) that 

appeared to be consistent with recommended lighting BMPs. 

Photo by A.J. Elmore. 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 5 

5-12 

operation, but they appeared to be consistent with the BMPs recommended by the states and by 

API. 

F. Construction of roads and pipelines 

Roads, pipelines, and other built linear features can have significant effects on even a largely 

forested landscape such as western Maryland. Fragmentation created by infrastructure 

development is a major threat to biodiversity and a primary concern resulting from MSGD (e.g., 

Alkemade et al. 2009). A recent meta-analysis of 49 studies on 234 species of birds and 

mammals found the effect of infrastructure to extend up to 1 km for bird populations, and 5 km 

for mammal populations (Francis et al. 2010). These impacts include: mortality from road 

construction, mortality from collision with vehicles, modification of animal behavior, alteration 

of the physical environment, alteration of the chemical environment, spread of exotics, and 

increased use of areas by humans (Trombulak and Frissell 2000). Threats to wildlife can be 

elevated by increased traffic on roads that have historically received little activity (Gibbs and 

Shriver 2005) and by genetic isolation of species with poor dispersal abilities (Keller et al. 2004). 

These studies illustrate the importance to terrestrial wildlife of minimizing new infrastructure 

development in lands that are currently relatively undisturbed. The potential impacts of road 

noise have been discussed above, and the consequences of increased impervious surface on 

aquatic resources are addressed in Chapter 6 of this report. 

A relatively sparse network of roads currently fragments the Marcellus Shale region of western 

Maryland, which translates to significantly lower cumulative ecological risk than the much 

denser road network of the eastern part of the state. In general, regions in which more than 60% 

of the total land area is within 1,250 ft of a road are at elevated risk of having those roads impact 

ecosystem condition (Riitters and Wickham 2003). The median distance to roads in western 

Maryland is currently 630 ft (Figure 5-6). The contribution of new roads to forest fragmentation 

is greatest in largely forested areas such as the Appalachian Mountains (Riitters and Wickham 

2003). An intensive network of new secondary roads and pipelines can be anticipated with 

MSGD. A study of the landscape changes due to natural gas extraction in the Marcellus shale 

region of Pennsylvania found an increase in forest edge of 380 miles in Bradford County and 721 

miles in Washington County between 2004 and 2010, with the largest amount (55%) attributable 

to road and pipeline construction (Slonecker et al. 2012). For both counties, pipeline construction 

was the major contributor to overall forest loss, increase in patchiness, and decrease in mean 

forest patch size. 

We recommend minimizing the amount and impact of new road and pipeline construction as 

much as practicable by following the guidance proposed by New York State: (1) limiting the 

linear distance of new roads through strategic siting of operations; and (2) co-locating project 

infrastructure with current roads, power lines, and pipelines (NYSDEC 2011). Centralization and 

co-location of infrastructure also offset air pollution by decreasing truck traffic (PADCNR 

2011). As the extent of road effects is thought to be at least as far-reaching as drilling 

operations, it would be most protective if all setbacks described in this chapter be applied to road 

construction as well as well-pad development: 300 ft from riparian areas, 600 ft from 

irreplaceable natural areas and wildlands, and 1,000 ft from caves. All new infrastructure 
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other equipment to be disinfected prior to moving the equipment for use at a new site15. 

Additional BMPs advocated by Pennsylvania DCNR include (PADCNR 2011): 

• A pre-construction inventory should be performed within the anticipated areas of disturbance to 

determine the appropriate prevention methods, predict control needs and assess its level of 

responsibility for management. 

• Soil disturbance should be minimized to decrease introduction. Consider co-location within 

previously disturbed areas and/or alternative construction methods. 

• The operator should clean equipment in an appropriate manner prior to bringing equipment into 

un-invaded areas or ecologically sensitive areas. 

• It is recommended that the operator use weed-free seed, soil, gravel, and mulch. Failure to use of 

weed-free material increases the potential to introduce invasive plant species and requires 

stringent monitoring. 

• Pre-treat invasive plant species infestations that reproduce prolifically from rhizome/root 

segments prior to disturbance. Pre-treatment may limit the spread of the invasive plant 

infestations upon completion of disturbance activities. 

• Disturbed areas should be surveyed annually at the appropriate time of year to detect early 

infestations. 

• Management and control of post-disturbance infestations of invasive plant populations should be 

species specific. In some situations, it may be best to wait another growing season to assess the 

spread before moving forward with management techniques. 

We recommend that permitting require specific plans for: (1) flora and fauna inventory surveys 

of sites prior to operations; (2) interim reclamation following construction and drilling to reduce 

opportunities for invasion; (3) annual monitoring and treatment of new invasive plant 

populations as long as the lease is active; and (4) post-activity restoration to pre-treatment 

community structure and composition using seed that is certified free of noxious weeds. 

H. Reclamation 

Reclamation and site decommissioning were discussed in Chapter 4 in the context of water and 

water quality management, but reclamation is also important in terms of providing forage and 

cover habitat for terrestrial species and minimizing opportunities for non-native plant invasions. 

Consistent with our recommendations in Chapter 4, reclamation planning should be conducted in 

two separate phases. Within an established period of time following the construction and drilling 

phases of development and bringing a well into production, any portion of a well pad site that is 

not needed for gas production should be revegetated. New York and Pennsylvania provide 

specific recommendations for this interim phase including creating soft edges around new 

clearings by maintaining current understory shrubbery or planting native plants (NYSDEC 

2011); revegetation should avoid wet seasons and wet periods outside of wet seasons to 

minimize impacts on soils, water, and vegetation (PADCNR 2011). Monitoring of native and 

invasive species could occur on-site throughout the length of the lease. For example, proposed 

protocols in New York call for monitoring of forest interior or grassland birds during the 

construction phase of the project and for a minimum of two years following well completion 

(NYSDEC 2011). A second phase of terrestrial habitat reclamation occurs after the wells have 

been plugged and gas production activities have ceased at a site. Permanent site restoration 

should remove the built infrastructure, restore the disturbed soil, re-contour the site, and provide 

 

15 Ibid.
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

5-15 

a permanent vegetative cover. Clear objectives for final site restoration should be specified as 

part of the permitting process. Options include reverting the site back to its original land cover or 

restoring the landscape to its native condition, which in this area of the country is forest cover. In 

all cases, species planted should be in their natural geographic range and local stock should be 

preferred (PADCNR 2011).

I. Key recommendations 

5-A Minimize well pad size, cluster multiple well pads, and drill multiple wells from each pad 

to minimize the overall extent of disturbance and reduce fragmentation and associated 

edge effects. 

5-A.1 Concentrate operations including roads on disturbed and open lands, ideally in 

locations zoned for industrial activity and/or close proximity to major roads. 

5-A.2 Adopt a no-net-loss of forest policy requiring any activities that remove forest to 

be offset by plantings elsewhere in the region. 

5-A.3 Implement comprehensive planning process to address the cumulative impact of 

multiple projects, to channel development into areas with greater amounts of 

existing disturbance, and to avoid areas with intact forests (especially forest 

interior habitat). 

5-B Allow for freshwater impoundments only. Impoundments should not be used for 

flowback or produced wastewater. 

5-B.1 Require watertight, closed metal tanks with secondary containment for all storage 

of chemicals and wastewater. 

5-B.2 Include runoff and spill prevention, response, and remediation plans as part of the 

permitting process 

5-C Establish and enforce setbacks to conserve terrestrial and aquatic biodiversity. 

5-C.1 Enforce 300 ft minimum setbacks from all floodplains, wetlands, seeps, vernal 

pools, streams, or other surface water bodies. 

5-C.2 Exclude all development activities from priority conservation areas (BioNet Tier I 

and Tier II sites and wildlands). Enforce a 600 ft setback from these areas. 

5-C.3 Enforce 1,000 ft setback from any cave to reduce stress to bats and other obligate 

subterranean species. 

5-D Review local noise ordinances to ensure they are sufficiently protective. Artificial sound 

barriers and mufflers should be considered where natural noise attenuation would be 

inadequate, especially in proximity to priority conservation areas. 

5-D.1 Avoid construction and drilling operations during sensitive migratory and mating 

seasons. 

5-E Reduce the amount of light pollution at drill pad sites by restricting night lighting to only 

when necessary and to only the amount of lighting required, direct light downward, 

instead of horizontally, use fixtures that control light directionality well, minimize glare, 

and use low pressure sodium (LPS) light sources whenever possible. 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 5 

5-16 

5-E.1 When drill pads are located within 1,000ft of aquatic habitat, vegetative screens 

and additional lighting restrictions could be required to reduce light pollution into 

these sensitive areas. 

5-F Co-locate linear infrastructure as practicable with current roads, pipelines and power lines 

to avoid new disturbance. 

5-F.1 Avoid stream crossings and any disturbances to wetlands and riparian habitat. 

5-G Submit an invasive species plan as part of permit application for preventing the 

introduction of invasive species and controlling any invasive that is introduced. 

5-G.1 The invasive species management plan should emphasize early detection and 

rapid response and include baseline flora and fauna inventory surveys of site prior 

to operations and long-term monitoring plans for areas that could become 

problematic after gas development occurs. 

5-H Develop a two-phased reclamation strategy comprised of (1) interim reclamation 

following construction and drilling to reduce opportunities for invasion and (2) postactivity restoration using species native to the geographic range and seed that is certified 

free of noxious weeds. 

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Recomm

Append

ended Best 

ix 5A

Management Practices for Marcell

5-19 

lus Shale Gas Development in Maryland
K.N. Eshleman & A.J. Elmore (2013) 

5-20 

 Chapter 5 
Recommended Best Management Practices for Marcell

5-21 

lus Shale Gas Development in Maryland
K.N. Eshleman & A.J. Elmore (2013) 

5-22 

 Chapter 5 
Recommended Best Management Practices for Marcell

5-23 

lus Shale Gas Development in Maryland
K.N. Eshleman & A.J. Elmore (2013) 

5-24 

 Chapter 5 
Recommended Best Management Practices for Marcell

5-25 

lus Shale Gas Development in Maryland
K.N. Eshle

(Hodges and 

et al. 2011), (

1993) 

eman & A.J. E

Krementz 1996), (

(Roe and Georges 

lmore (201

Bried and Ervin 2

2007), (Semlitsch 

3) 

006), (Burke and 

1998), (Semlitsch

5-26 

Gibbons 1995), (C

 and Bodie 2003)

rawford and Sem

, (Wanger 1999), (

litsch 2007), (Gam

(Castelle et al. 199

 Ch

ble et al. 2006), 

4), (McComb et a

hapter 5 

(Perry 

l. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-1 

6. Protecting aquatic habitat, wildlife, and biodiversity1

Freshwater aquatic habitats (defined as all streams, rivers, seeps, springs, wetlands, lakes, ponds, 

reservoirs, and floodplains) are unique and critical components of watersheds, providing hotspots 

of biodiversity and transfers of energy, nutrients, and matter to coastal ecosystems such as 

Chesapeake Bay (Likens and Bormann 1974, Lowe and Likens 2005, Alexander et al. 2007, 

Meyer et al. 2007). Risks to aquatic habitat and wildlife from Marcellus shale gas development 

activities are numerous and include both direct impacts to the aquatic environment through stream 

dewatering, runoff generation, non-point and point source pollution, elevated thermal regimes, and 

indirect impacts through riparian habitat degradation. In Chapter 4 we discussed the possible 

adverse impacts of temporary stream dewatering on surface water supplies, but it must be 

emphasized that streamwater itself is a critical physical habitat characteristic that must be 

maintained to support aquatic biota, including species that contribute to Maryland’s biotic 

diversity and recreational opportunities (e.g., trout). Land surface and channel erosion can greatly 

increase suspended sediment concentrations and turbidity levels—particularly during runoff 

events—resulting in decreases in water clarity and increased sedimentation of fine materials. 

Turbidity and sedimentation reduce water column and benthic light availability, influencing fish 

foraging success and the quality of substrate for habitat. Excessive sedimentation fills the pore 

spaces in which fish lay their eggs, adversely impacts benthic organisms such as freshwater 

mussels, and reduces the production of submersed aquatic vegetation (SAV). Increases in water 

temperature due to forest clearing, riparian vegetation disturbances, or the inadvertent discharge of 

previously impounded water into streams could negatively affect habitat quality and impose 

additional stresses on trout and other cold-water fish populations. 

Conservation of aquatic habitat and wildlife requires more extensive analysis than a simple 

evaluation of the closest wetland or stream landscape feature. The numbers of tributaries, and their 

respective size and location within the stream network (Palmer et al. 2000, Benda et al. 2004) are 

critical to understanding population dynamics and ecosystem function (Rice et al. 2001, Rice et al. 

2006). Organisms certainly vary in their susceptibility to disruptions in aquatic habitat quality, 

area, and connectivity due to variation in degree of habitat specificity (e.g., restricted movement 

within a small range of stream size) and ability or inability to travel over land between wetlands or 

stream reaches (Fagan 2002). While less common than dispersal within aquatic habitat, overland 

dispersal plays a critical role in the exchange of individuals and genetic material between distant 

populations (Bunn et al. 1999, Bilton 2001). Human alteration of land cover proximate to and 

between aquatic habitat has the potential to adversely impact the fitness, survival, and mating 

success of a wide variety of organisms (Oke et al. 1989, Sweeney 1993, Urban et al. 2006), 

leading to population declines or localized extinctions by restricting overland dispersal. As part of 

a comprehensive plan for conserving aquatic habitat and wildlife, Maryland should consider the 

larger landscape context of aquatic habitat. This should include considering: (1) how habitat is 

connected through physical transport and biological dispersal; and (2) cumulative impacts to 

watersheds from the combined effects of agriculture, urbanization, and MSGD. Because 

conservation of aquatic habitat, wildlife, and diversity is related to land use within the entire 

watershed, much of the discussion of terrestrial habitat, wildlife, and biodiversity is relevant to this 

 

1

 Chapter co-authors: Andrew J. Elmore, Ph.D., and Keith N. Eshleman, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532) 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-2 

chapter and many of the key recommendations (e.g., riparian buffer setback distances) were 

discussed in Chapter 5. 

Figure 6-1. Stream density in western Maryland ranges from approximately 1.5 km/km2 (stream length divided by 

watershed area) in the west to nearly 4.0 km/km2

 in the east (Julian et al. 2012, Elmore et al. in review). High stream 

density has the potential to complicate the siting of well pads, particularly in Stronghold watersheds (cyan) or where 

reproducing populations of native brook trout2

 have been identified (purple)3. Many streams contain unique 

assemblages of rare, threatened and endangered species and all streams are essential hotspots for biotic life, 

supporting a wide range of visitors from the terrestrial landscape. Maryland DNR as part of their Maryland Biological 

Stream Survey measures stream community composition annually4

. Recent work to synthesize these data has 

advanced in many areas resulting in detailed maps (inset) delineating classes of stream reaches with similar 

community composition (represented by different colors in the map)5

. 

During Marcellus shale gas development, BMPs could be employed that reduce non-point source 

pollution, maintain habitat of sufficient quality for rare, threatened, and endangered species as well 

as for species of significant commercial or recreational value (e.g., trout fisheries), and limit the 

introduction of non-native species. Fortunately, Maryland’s aquatic environment has been under 

intensive study for many decades, including detailed stream survey work (MDNR 2010) and 

synthetic analyses aimed at establishing robust descriptions of both reference and impacted aquatic 

populations (Utz et al. 2009). There are many important considerations to be made when 

evaluating potential BMPs, but perhaps the most important is to generate and use accurate maps of 

wetlands and the stream network (Julian et al. 2012, Elmore et al. in review). Such data ideally 

 

2

 Data on stronghold watersheds and brook trout were acquired from Maryland Department of Natural Resources 

3

 Additional complications can arise when MSGD is proposed in Tier II streams and watersheds. We view this as a 

water quality concern and therefore address this topic in Chapter 4; however, clearly the available BMPs have 

considerable overlap. 

4

 Maryland Department of Natural Resources. 2010. Retrieved from http://www.dnr.state.md.us/streams/MBSS.asp 5

 Unpublished model results, Matthew Fitzpatrick, UMCES, Appalachian Laboratory. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-3 

provide a detailed spatial representation of the aquatic resources at risk and their proximity to the 

proposed development. BMP selection should also be sensitive to existing conservation efforts, 

which are currently used in Maryland to identify watersheds and wetlands of particular value to 

the overall biodiversity of Maryland’s aquatic habitat and to identify current threats to this 

biodiversity (e.g., climate change). As has been the case in Maryland’s neighboring states that 

have active shale gas development, a variety of BMPs have been developed that cover activities in 

both upland and riparian environments. To best protect aquatic, wetland, and riparian habitats and 

wildlife in Maryland, the choice of BMPs should be based on the best available science and 

detailed site analyses. 

A. Buffers and setbacks 

A primary BMP that has been widely employed to mitigate against adverse impacts on aquatic 

systems is the use of a forest riparian buffer or, where forest is not present, a minimum setback 

distance from aquatic habitat. Upland forest buffers provide benefits to aquatic environments that 

can be classified as chemical, physical, or biological. The scientific basis for imposing a buffer 

with a specific width depends on the overall rationale for the buffer. Many favorable chemical and 

physical characteristics (e.g., stream nitrate concentration, sediment concentration, water 

temperature, benthic light availability) can be achieved by imposing a relatively small forest buffer 

that might not be much wider than the average canopy height (~100 ft). Consequently, a broad 

array of literature that focuses on aquatic habitat condition and biological diversity supports the 

adoption of a 100 ft buffer from aquatic habitat (see Wanger 1999 and references therein). Wider 

buffers are required to protect herptiles (reptiles and amphibians) that use forest riparian buffers 

(particularly on floodplains) for forage or dispersal. Therefore, the most appropriate forest riparian 

buffer width is generally larger than what would be determined if only the aquatic environment 

were considered. For this reason, forest riparian buffer widths described in Chapter 5 (terrestrial 

biodiversity conservation) generally supersede setbacks required for aquatic habitat, wildlife, and 

biodiversity wherever forest is present in the proposed setback. 

Where forest riparian buffers are not present, either because agricultural activity or developed land 

cover extends all the way or most of the way to aquatic habitat, the benefit realized from setback 

restrictions can take different forms. Setbacks from aquatic habitat in agricultural lands can be 

justified wherever MSGD would produce stormwater runoff, potentially transporting sedimentladen or nutrient-rich water to streams, rivers, and wetlands. For example, productive pastures 

have the potential to abate the impact of such stormwater before it enters aquatic habitat. 

Similarly, in urban settings setbacks provide needed space for stormwater management, including 

retention and diversion of stormwater, thus reducing the chance that any spills and leaks would 

lead to contamination of aquatic habitat (see Chapter 4). Finally, in all settings (forest, agricultural, 

and urban), setbacks from aquatic habitat provide benefits to recreational resources. Many 

streams, some located close to urban and suburban communities, are used frequently for birding, 

fishing, boating, and swimming. To maintain the quality of these locations and reduce conflicts 

with these other uses, MSGD infrastructure should always be set back from aquatic habitat. 

Wherever possible, this setback should be forested (i.e., a riparian forest buffer) and Maryland 

should use MSGD as an impetus to continue it’s overall efforts to increase the coverage of riparian 

forest buffers throughout western Maryland (e.g., mitigation plantings under Maryland’s no-netloss of forest program). However, as stated above, the lack of forest in the riparian zone should not 

be used as justification to reduce the setback distance. 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-4 

As in many other states, no direct disturbance of any aquatic habitat for shale gas development 

should be permitted in Maryland. We specifically define direct disturbance as any site preparation, 

earth-moving, well pad construction, grading, well drilling, equipment storage, or other 

development activity on the land surface anywhere aquatic habitat is present (exceptions would be 

disturbances associated with any necessary access road, utility and pipeline corridor construction 

activities that are specifically addressed in a later section of this chapter). In addition, consistent 

with the most stringent setback requirements that we identified in our reviews (Lien and Manner 

2010), we recommend that a minimum 300 ft aquatic habitat setback be applied in western 

Maryland (with the distance measured from the edge of any land disturbance, not from the 

location of a particular wellbore, to the edge of a particular habitat). Because setbacks are intended 

in part to reduce the chance that spills of contaminated or sediment laden water reach aquatic 

habitat, the 300 ft setback should not be decreased in situations where the setback space is already 

cleared of forest (e.g., in agricultural settings). In all cases the intent is to protect the aquatic 

habitat, therefore while slope, land-cover, and soil condition likely influence the calculation of the 

most appropriate setback distance, a 300 ft setback should never be reduced. The 300 ft setback is 

consistent with, but slightly more protective, than what is being proposed or used in other states.

Pennsylvania DCNR uses a 300 ft no-disturbance buffer for situations where a body of water 

contains threatened or endangered species or is considered either a high quality or exceptional 

value stream or body of water6

. Similarly, West Virginia also enforces a 300 ft buffer for 

development near streams with naturally reproducing trout populations7. The 300 ft buffer exceeds 

the 100 ft requirement used on non-DCNR lands in Pennsylvania, as well as the 150 ft 

requirement used by New York for conventional gas development to protect permanent surface 

bodies of water and springs that provide domestic water (NYSDEC, 2011). 

Due to the nature of horizontal drilling and the 

linear shape of many aquatic habitats (e.g., 

streams and rivers), the requirement of a 300 ft 

minimum setback will not significantly restrict 

the placement of MSGD infrastructure. Through 

the use of compact industrial parks for MSGD, 

we are confident that MSGD operators will be 

able to effectively access the majority of 

Marcellus shale gas reserves without disturbing 

lands within 300 ft of streams. Further, the 

topography of western Maryland is highly 

dissected, with the majority of streams located in 

deep, narrow ravines. Once out of these ravines, 

the Appalachian Plateau affords considerable 

area of relatively flat (<15% slope) land that, if 

other conditions are met, could be available for 

MSGD. Excluding floodplains8

, which we do not 

 

6

 However, PADEP enforces a 150 ft buffer for high quality streams and a 100 ft buffer for Class A trout streams 

outside of Pennsylvania state forests. 7

 West Virginia Horizontal Well Act; 

http://www.legis.state.wv.us/Bill_Status/bills_text.cfm?billdoc=hb401%20enr.htm&yr=2011&sesstype=4X&i=401. 8

 Floodplains can be adequately described by FEMA floodplain maps, which have recently been updated for western 

Maryland. 

Figure 6-2. A plot of mean slope vs. distance to a stream 

reveals that aside from the floodplain (occurring on average 

within the first 100 ft of streams), the mean slope of land 

within 300 ft of streams is too steep for MSGD (i.e., > 

15%). Note that the mean slope includes many very steep 

ravines, which skews the mean towards higher than 

expected values. In a separate calculation we found that 

only 40% of lands within the 300 ft stream setback were 

sufficiently flat to accommodate MSGD. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-5 

recommend for MSGD, only 40% of the area within 300 ft of streams exhibits a slope <15%, 

making it appropriate for MSGD. This statistic, combined with the fact that most of the area 

within 300 ft of streams is forested (and no-net-loss of forest is recommended), suggests that there 

are multiple interacting characteristics of lands within 300 ft of streams that make these lands 

unsuitable for MSGD. 

Figure 6-3. Wetlands in western Maryland are defined for regulatory purposes by the National Wetlands Inventory9

(NWI) and by additional mapping efforts conducted by the Maryland DNR10. Total wetland area as defined by the 

union of these data sets is 20,000 acres, 7000 acres of which is made up of small wetlands with an area less than 10 

acres. Certain wetlands with rare, threatened, endangered species or unique habitat receive special attention. Code of 

Maryland Regulations (COMAR) Title 26, Subtitle 23, Chapter 06, Sections 01 & 02 identify these Wetlands of 

Special State Concern (WSSC) and affords them additional protections; MDE is responsible for identifying and 

regulating these wetlands. 

B. Special protection of high-value assets 

We have identified many examples of specific BMPs that are being used by other states to provide 

additional protection of high-value or highly sensitive assets such as 100-year floodplains, 

wetlands, high quality streams, natural trout streams, and rare, threatened and endangered species 

beyond that provided through minimal setbacks. It has been strongly recommended that states 

with actual or proposed unconventional gas development undertake efforts to identify critical areas 

with known endangered species, unique habitats, significant migration and breeding areas for 

birds, mammals and aquatic organisms, and significant riparian areas (Lien and Manner 2010). 

 

9

 U.S. Fish and Wildlife Service. 2012. National Wetlands Inventory website. U.S. Department of the Interior, Fish 

and Wildlife Service, Washington, D.C. http://www.fws.gov/wetlands/ 10 All DNR data for this map was acquired from Maryland Department of Natural Resources at 

http://dnrweb.dnr.state.md.us/gis/data/index.asp
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-6 

The goal would be to develop maps that would allow identification and consideration of high 

value assets before initial site selection, thus reducing the chance of selecting sites that turn out to 

be unsuitable or unfeasible for MSGD. Pennsylvania has already developed a Pennsylvania 

Natural Diversity Inventory (PNDI) and associated Environmental Review Tool (ERT) that allows 

the public, a consultant, property owner, or project planner to perform on-line searches to identify 

potential impacts to threatened, endangered, special concern species and special concern resources 

in the Commonwealth. The ERT can now accommodate linear projects up to 10 miles in length 

and area projects up to 1,200 acres in size; projects that exceed these limits can be submitted for 

environmental review as “large projects”. The County Natural Heritage Inventory (CNHI) effort in 

Pennsylvania is another example of a cooperative program undertaken by the Pennsylvania 

Natural Heritage Program (PNHP) partnership. The CNHI performs systematic studies of critical 

biological resources of the state on a county-by-county basis that form the basis for the PNDI 

permit review data. 

As discussed in Chapter 1, prior to submitting a drilling application or comprehensive drilling plan 

for review and approval, a prospective shale gas developer could be required to consult available 

data on high-valued biological and water quality assets (e.g., Tier II streams and watersheds, see 

Chapter 4) within the western Maryland region. Similar to activities in other states, such an 

exercise would ideally allow a prospective operator to quickly determine the applicable BMPs 

governing MSGD at a particular site—thus saving considerable time and money during the 

planning stages of a project. To support this effort, Maryland will likely need to continue its 

efforts to identify high-value assets and publish in the scientific literature the methods used to 

make this designation. Maryland has made considerable progress in this area with the creation of 

its BioNet classification of irreplaceable natural areas (Chapter 5). Addressing aquatic biodiversity 

specifically, Maryland has taken the BioNet approach one step further by identifying those 

“stronghold watersheds” (Figure 6-1) that are: (1) the most important areas for the protection of 

Maryland’s aquatic biodiversity; (2) where rare, threatened, or endangered freshwater fish, 

amphibians, reptiles, or mussel species occur in the highest densities; and (3) where special 

protection is deemed necessary to ensure the persistence of imperiled fauna11. When documented 

properly, such data could be effectively used to channel MSGD into watersheds or sites within 

watersheds where it will have the least impact on aquatic habitat and biodiversity. 

The use of “stronghold watersheds” implicitly assumes that aquatic biodiversity conservation 

should take a “watershed approach” since some particularly sensitive species may cease to persist 

if even relatively small portions of these watersheds become degraded. Such is the case with 

remaining populations of brook trout (Salvelinus fontinalis), which is the only salmonid native to 

Maryland. Brook trout were once widely distributed throughout the central Appalachians, 

including western Maryland. Brook trout are sensitive to increased stream temperatures 

(McCormic et al. 1972, Eaton and Scheller 1996), sediment and habitat alteration, and altered 

stream chemistry (Leivestad 1982, Mount et al. 1988, Ingersoll et al. 1990). Altered land use is 

associated with disappearance of brook trout populations, with sensitivity to agriculture west of 

the Blue Ridge in Maryland (Utz et al. 2010) and near universal extirpation from watersheds 

exceeding 4% impervious surfaces (Stranko et al. 2008). Brook trout are now dramatically 

reduced throughout their historic range (Hudy et al. 2008). Although populations occasionally 

occur in highly modified watersheds, these are the exceptions rather than the rule, as is evident by 

 

11 http://www.streamhealth.maryland.gov/stronghold.asp
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-7 

their continued disappearance from watersheds. Many of Maryland’s populations currently inhabit 

only portions of streams, are disconnected from other streams, and are present at low abundances. 

Thus, many of the existing populations do not have sufficient space or numbers for long term 

viability (Hilderbrand and Kershner 2000, Hilderbrand 2003) and many existing populations will 

likely be extirpated within 20 years if the previous 20 years is a guide (Stranko et al. 2008)). 

Activities that decrease abundance or fragment existing populations will further increase 

extirpation risk in even the stronghold watersheds. 

Our research into BMPs proposed or in use to protect aquatic habitat in other states suggest that 

stream setbacks represent the primary instrument used to provide protection of aquatic 

biodiversity, which in many cases leaves the door open to cumulative impacts from the linear 

combination of many disturbances, regardless of their distance to aquatic habitat. Increasing 

setbacks might offer some additional protection, but primarily for species with terrestrial life 

stages (see Table 5-3). Therefore, some states have included language attempting to address 

cumulative impacts in other ways. For example, in Colorado the responsibility is put on drilling 

operators to minimize land disturbance, consolidate facilities, and co-locate infrastructure 

whereever possible. Similarly, in Pennsylvania, operators are required to provide PADEP with a 

description of their efforts to avoid, minimize, or mitigate for impacts to high-valued biological 

assets (e.g., co-location and centralization of infrastructure, use of specialized BMPs, well pad 

spacing and density adjustments, working with other companies holding leases in this area to 

reduce cumulative impacts, etc.). In particular, there is recognition that minimizing the number of 

well pads through coordinated planning, consultation, and utilization of existing rights of way, can 

mitigate the cumulative impact on forests. Our opinion of these efforts is that, while well intended, 

they generally lack teeth, and will do little to address cumulative impacts in watersheds highly 

sensitive to even low levels of development. 

In select high-value watersheds12, Maryland should consider novel ways of establishing areal 

limits on surface development of all kinds (e.g., residential, commercial, wind power, 

unconventional shale gas, etc.) to address cumulative impacts. There is substantial scientific 

evidence that aquatic habitat and biodiversity respond to cumulative land disturbances or land use 

changes (e.g., urbanization), either linearly or non-linearly (Booth et al. 2002, Walsh et al. 2005, 

Petty et al. 2010, Merriam et al. 2011). While establishing fixed response thresholds for aquatic 

systems has proven difficult, there is considerable empirical evidence from the urban stormwater 

literature that cumulative surface imperviousness causes declines in aquatic biodiversity or 

ecological condition beginning at impervious cover well below 10% (Walsh et al. 2005, Petty et 

al. 2010). In Maryland’s Piedmont watersheds, over half the aquatic insect species have become 

extinct from watersheds with 10% impervious cover (Utz et al. 2009). Among the most sensitive 

aquatic species is brook trout, which is almost entirely restricted to watersheds with less than 4% 

impervious surface (Stranko et al. 2008). 

To provide an adequate margin of safety, we recommend that cumulative impervious cover 

(including all well pads, access roads, public roads, etc.) be maintained at less than 2% of the 

watershed area in select high-valued watersheds. In some cases, stronghold and Tier II watersheds 

(e.g., the Savage River watershed) might be excellent candidates for such additional protections, 

but also possibly many or all of the watersheds containing brook trout. However, additional 

 

12 For example, stronghold watersheds and Tier II watersheds, the second of which have anti-degradation protection 

under MDE’s Clean Water Act regulatory authority (see Chapter 4). 
K.N. Eshle

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Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-9 

C. Design and construction of well pads, access roads, pits, utility corridors, and 

pipelines 

Implementation of BMPs in design and construction of well pads, access roads, and other ancillary 

infrastructure associated with Marcellus shale gas development can also minimize degradation or 

losses of aquatic habitat and aquatic biodiversity. In addition to utilizing appropriate nodisturbance setbacks to protect aquatic habitat, proper implementation of appropriate erosion and 

sediment control measures (see Chapter 4) and stormwater pollution prevention techniques are 

important ways that aquatic habitat can be conserved. 

Well pads. We have recommended “zero-discharge” well pads as a BMP for western Maryland 

primarily to control stormwater (and associated sediment pollution; see Chapter 4), as well as 

spills/leakage of chemicals from the surface to ground and surface water systems. We expect 

stormwater impacts to be most significant during well pad construction when the system is most 

susceptible to failure resulting from heavy rainfall events and after well drilling and completion 

activities have ended and active collection, treatment, and disposal of stormwater runoff has 

ceased. During well drilling when well pads are being regularly monitored, operation of passive 

and active stormwater collection should be able to minimize downstream impacts from the pad 

(i.e., this is the period in which stormwater can be actively collected in vacuum trucks, treated, 

disposed of, or used on site). Vacuum trucks should be kept on site throughout the period in which 

active stormwater collection is needed. However, only passive structural stormwater BMPs would 

be operational after well development is completed (or possibly during periods between individual 

well drilling events). Under these conditions, and without additional BMPs, the well pad would 

likely be functioning largely as an impervious surface, thus increasing stormwater discharge, 

channel erosion in small receiving streams, and downstream sedimentation. Stormwater could also 

become contaminated with salts or other pollutants through leaks from produced water storage 

tanks or liquid lines on-site, or from tanker trucks used to transport the produced water off-site. 

Therefore, other (passive) urban stormwater BMPs would still be needed. Since there exists the 

very real possibility that runoff from these pads could carry pollutants off-site, we do not 

recommend use of any BMPs that would promote infiltration due to the concern for groundwater 

pollution. The best solution for addressing both quality (i.e., suspended solids) and quantity (i.e., 

peak discharge) issues might be through construction of a below-grade lined pond adjacent to the 

bermed zero-discharge pad that could be used as a sump during active stormwater management 

phases and easily converted into a retention pond prior to any passive phases. Regular (annual) 

maintenance of the pond would also be needed to ensure that the system is functioning correctly at 

all times. Additional water quality treatment could be obtained through operation of a constructed 

wetland sited downstream of the pond outlet. 

As discussed in Chapter 4, these recommendations are at least in partial conflict with two of 

Maryland’s performance standards for controlling stormwater pollution13: standard no. 1: site 

designs shall minimize the generation of stormwater and maximize pervious areas for stormwater 

treatment; and standard no. 2: annual groundwater recharge rates shall be maintained by 

promoting infiltration through the use of structural and non-structural methods. Clearly, 

 

13 Maryland Stormwater Design Manual , Volumes I & II (effective October 2000, revised May 2009); 

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManual/

Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-10 

Maryland’s stormwater designs originate from experience mostly with urban and suburban 

development and thus emphasize the use of BMPs that tend to maximize infiltration. Since these 

are not recommended, there will need to be some significant attention given to alternative 

approaches such as the ones we have identified to address these problems during periods when 

active stormwater management would not be a viable option. 

Access roads. Wherever feasible, use of existing roads is the preferred option for facilitating 

transport of materials and personnel to well sites. However, we anticipate that there will be many 

cases where existing roads are nonexistent or inadequate and new roads will be needed. To protect 

aquatic habitat and minimize associated stormwater runoff, the design, routing, construction, and 

maintenance of any access roads to a well pad should be done in a manner that can safely support 

considerable heavy truck traffic, minimizes the clearing of forests, avoids steep slopes, avoids 

wetland and stream crossings, utilizes bridges or arched culverts for all stream crossings (leaving 

the stream bed relatively undisturbed), and promotes sheet flow runoff from the road surface onto 

surrounding soils wherever possible. Roads should not be located in or parallel to perennial or 

intermittent stream channels (i.e., no stream fords). Consistent with Pennsylvania DEP proposed 

rules, all wetland crossings should be avoided. Pennsylvania DCNR describes particularly good 

practices for constructing and maintaining such gravel roads to facilitate Marcellus shale gas 

development in Pennsylvania state forests that would also be highly applicable to western 

Maryland (PADCNR 2011). For road construction, Pennsylvania DCNR: (1) recommends 

utilizing materials and designs (e.g., crowning, elimination of ditches, etc.) that encourage sheet 

flow as the preferred drainage method for any new construction or upgrade of existing gravel 

roadways; (2) provides specific recommendations about aggregate depth, type, and placement; and 

(3) promotes the use of geotextiles as a way of reducing rutting and maintaining sub-base stability 

(PADCNR 2011). In Pennsylvania (as in western Maryland), it is typical for water to be a seasonal 

problem on dirt and gravel roads and one of the best ways to minimize the risk of road failures is 

to selectively schedule hauling operations to avoid or minimize traffic during the spring thaw and 

other wet weather periods. 

Pits. We do not recommend the use of any open pits on-site for collecting and storing drilling 

wastes, flowback, or produced water due to concerns about surface water quality (see Chapter 4). 

We strongly recommend closed drilling systems in which all drilling and hydraulic fracturing 

fluids, chemicals, and liquid wastes are collected and stored in steel tanks that provide superior 

primary containment. Secondary containment can be provided by berms and liners placed 

strategically under tanks and areas where liquid transfers take place. Tertiary containment can be 

provided by construction of zero-discharge pads. 

Utility corridors and pipelines. In addition to providing vehicular access to sites, road corridors 

can also be designed and constructed to facilitate below-ground transmission of gas, water, and 

AC power (if desired) to each well pad (as in the case of Pennsylvania state forests). Gathering (or 

feeder) pipelines provide a way of transmitting the gas to compressor stations and to larger 

transmission pipelines that would also need to be co-located along major roads and highways. 

Flexible (e.g., HDPE) pipelines could be used to transmit water to each well pad to support 

hydraulic fracturing operations. AC power could be used to power drilling equipment, lights, and 

other equipment on-site (in lieu of diesel generators). At Tiadaghton State Forest, for example, it 

was possible to co-locate such infrastructure within a ~35-foot wide corridor immediately adjacent 

to the access road. Co-location of this ancillary infrastructure along the road corridor helps 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-11 

minimize the extent of surface disturbance. Another viable alternative that would further minimize 

surface disturbance is transfer of freshwater in flexible pipes above ground (King 2012)—although 

this practice might be problematic in western Maryland where winter temperatures could cause 

these pipes to freeze and burst. 

Wherever possible, any belowground transmission of gas, water, and AC power should be colocated with road infrastructure to minimize impacts on aquatic habitat. Aquatic habitat crossings, 

where necessary, should be accomplished with appropriate use of bridges or arched culverts to 

ensure free flow of water, particularly during flood stages (API 2011). The ecological effects, 

particularly on fish populations such as brook trout, of in-stream disturbance and semi-permanent 

barriers to dispersal (e.g., culverts) are well documented, and therefore should be avoided 

wherever possible (Burns 1972, Barton 1977, Meyer et al. 1999, Poplar-Jeffers et al. 2009). As in 

New York, when utility lines are to be buried beneath streams, minimum burial depths should be 

enforced (NYSDEC 2011). Due to documented impacts of road crossings on fish spawning 

success (Lachance et al. 2008), a general trout spawning substrate evaluation by DNR biologists 

should be required if any portion of a stream is expected to sustain a temporary or permanent 

blockage to fish passage. Alternatively, Maryland could ban the practice of diverting streams for 

any purpose and require the building of bridges or arched culverts to accomplish stream crossings. 

Likewise, open trenches within streams should be avoided in favor of using directional boring 

techniques for installation of pipelines. Directional boring is a trenchless construction technique 

by which an operator can drill down next to a stream, bore horizontally under a stream, and then 

bore up to the surface on the other side. The technique is highly advantageous over stream 

trenching because it leaves the stream banks and streambed intact and the need for temporarily 

dewatering the stream is eliminated. Risks associated with directional boring are related to the 

possibility of encountering unexpected subsurface voids, which have the potential to release 

drilling fluids and cuttings into stream waters. While such an event would be unfortunate, we 

believe the benefits of directional boring outweigh the risks, which can generally be mitigated for 

by maintaining a depth of at least 10 ft below the streambed and avoiding drilling through highly 

fractured substrate. In addition, efforts should be taken to avoid surface and subsurface spills or 

leaking of drilling fluids. 

Surface impoundments. There are currently no construction standards for the kind of small (< 15 

MG) freshwater impoundments that are being used throughout the state to temporarily store water 

prior to its use for hydraulic fracturing in Pennsylvania (Marcellus Shale Advisory Commission, 

2011), although larger impoundments require dam construction and operation permits). The 

facility that one of us (KNE) visited in Tiadaghton State Forest was a shallow (3-4 ft deep), lined 

pond equipped with automated water level monitors that is capable of being continuouslymonitored from either a remote or centralized office location (Figure 1-4). Adequate freeboard can 

be maintained by pumping out water as needed, and a series of standpipes provide a means of 

safely refilling the pond from water tankers. A buried pipeline enables transfer of water from the 

impoundment to nearby well pads. This seemed to be a particularly well designed facility that 

effectively isolated the stored water from the stream network (i.e., there is not an obvious 

mechanism other than overflow of the structure by which non-native species could be introduced 

into a nearby waterway). At a minimum, planning for one of these facilities should include 

precautionary measures to identify invasive species at water sources and avoid transporting these 

species to impoundments located in watersheds where these species are not present. Further, the 

discharge of any impounded water back into a natural water body should be prohibited to avoid 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-12 

increasing water temperatures in groundwater fed streams and to avoid inadvertent non-native 

introductions. 

Surface water intake structures. Intake structures should be designed to avoid entrainment of 

aquatic organisms (Lien and Manner 2010) and invasive species management plans should include 

procedures for effectively washing intake equipment before leaving the site (see below). 

D. Erosion and sediment controls 

High quality headwater streams—tributary streams, intermittent streams, and spring seeps — are 

essential to the health of stream and river ecosystems. Headwaters, when functioning properly, 

help to reduce sediment in the lower reaches of the stream network. Forested buffer zones slow 

erosion during peak stream discharge and help maintain low stream water temperatures, a critical 

factor in streams that support trout and other cold-water species (e.g., Koehn and Hairston-Strang 

2009, Henley et al. 2010). When forested buffers are removed or when headwater streams are 

directly disturbed, these channels become conduits for sediment and pollution that leads directly to 

larger streams and coastal receiving waters (Kaplan et al. 2008). The direct effects of sediments on 

fish will vary with the concentration of suspended matter, duration and timing of exposure, degree 

of sediment deposition, particle size distribution and type of sediment, and fish species and life 

stages at which the fish is exposed (Kemp et al. 2011). Known impacts from sediments in streams 

include: (1) reduced photosynthesis throughout the water column leading to reduced primary 

productivity and, therefore, reduced forage for higher trophic levels; (2) reduced periphyton 

attachment (a mixture of algae, cyanobacteria, heterotrophic microbes, and detritus found in most 

aquatic habitats) and macrophyte growth, leading to reduced animal and plant abundance, species 

richness, and diversity; and (3) increased sediment deposition and the loss of physical habitat 

(Kemp et al. 2011). 

Best management practices for sediment and erosion controls are covered in detail in Chapter 4. 

Aside from forest buffer disturbance (which we recommend protecting against with a 300 ft 

riparian forest buffer), much of the risk to aquatic habitat, and headwater stream ecosystems 

specifically, comes from ungraded roads on steep slopes or erodible soils, and stream crossings. 

Research has shown that 90% of the sediment that ends up in our nation’s waters from forested 

lands is associated with improperly designed and maintained roads (Daniels et al. 2004). 

Unsurfaced roads, even with only moderate levels of light vehicle traffic, produce the greatest 

amount of sediment per unit of rainfall. Gravel roads with a maintained driving surface of 

sufficient aggregate can be built to produce significantly less sediment (Sheridan and Noske 

2007). In Chapter 4 and elsewhere in this report we discussed the importance of regulating road 

construction during MSGD and have recommended the use of gravel road design principles 

recommended by Pennsylvania DCNR (PADCNR 2011). Many BMPs related to road construction 

have proven effective, including elevating the road profile, building grade breaks and additional 

drainage features, removing berms, etc. (e.g., Scheetz and Bloser 2008). Other possible BMPs 

include the use of silt fencing, sedimentation ponds, mulches, and grass seeding, which have been 

shown to be effective at sediment removal during periods of little rain, but inadequate during 

periods of flashy flows typical of mountain streams (Hedrick et al. 2010). Therefore, using a 

combination of BMPs and recognizing that additional protective measures might be necessary 

during certain times of the year (primarily late winter and early spring), is itself a BMP for 

Maryland. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

6-13 

E. Invasive species controls 

Equipment used in MSGD is often transported great distances and used in relatively pristine 

watersheds. In particular, water withdrawals from large rivers and reservoirs (where permitted) 

have the potential to introduce non-native and invasive species that can become a risk to native 

aquatic habitat and biodiversity. Maryland should take precautions to reduce the transmission of 

invasive plant and animal species by requiring an invasive species management plan of industry 

prior to any drilling operations. Of particular concern is the potential for harmful algal blooms 

(HAB), such as those produced by the non-cyanobacterial taxa, Prymnesium parvum (commonly 

known as “golden algae”), which is likely the most problematic HAB taxa in U.S. waters. P. 

parvum has caused large fish kills worldwide since as early as the 1930’s, and was first suspected 

of fish kills in Texas in 1982 and confirmed in 1985 (Lopez et al. 2008). P. parvum blooms can 

span many miles, across entire lakes, and can even propagate hundreds of miles downriver. This 

algae has been implicated in the largest fish-kill associated with MSGD in PA and WV (Dunkard 

Creek), suggesting it is an emerging threat to freshwater systems throughout the region (Brooks et 

al. 2001, Renner 2009). 

To protect aquatic habitat, each operator should be required to submit a site-specific invasive 

species management plan prior to any drilling operations. Such a plan should describe procedures 

to be used during any water withdrawal from a local water source. At the very minimum, 

equipment should be power-washed and rinsed with clean water before leaving the withdrawal 

site. Loose plant and soil material (potentially containing seeds, roots, or other viable plant parts) 

and unfiltered water, that has been removed from clothing, boots and equipment, or generated 

from cleaning operations, should be disposed of in appropriate containers for disposal. During 

power washing, wash water (including spray) should not discharge within 100 ft of any stream, 

existing or proposed wetland, or stormwater conveyance (e.g., ditch, storm drain, etc.). In no 

circumstances should water that has been transferred between watersheds or moved upstream 

above confluences be discharged into aquatic habitat. This would include water that has been 

stored in tanks or impoundments, but was not subsequently used in the drilling or completion 

process. 

F. Key recommendations 

6-A Direct disturbance of any aquatic habitat for shale gas development should not be 

permitted. 

6-B A minimum 300 ft aquatic habitat setback should be applied, with the distance measured 

from the edge of any land disturbance, not from the location of a particular wellbore, to the 

edge of a particular habitat. 

6-C Data that describe the biological resources of western Maryland should be developed and 

made available to MSGD applicants. These data should be used to effectively channel 

development away from high-value biological resources and into industrial zones 

accessible via existing roads and highways. 

6-D The use of multi-well pads to access relatively large (~2 mi2

) resources of shale gas would 

enable the maintenance of reasonably low levels of surface development. 
 K.N. Eshleman & A.J. Elmore (2013) Chapter 6 

6-14 

6-E Cumulative surface development (including all well pads, access roads, public roads, etc.) 

could be maintained at less than 2% of the watershed area in high-value watersheds. 

6-F Initially, all MSGD could be excluded from areas of high-value assets (e.g., BioNet sites, 

stronghold watersheds, Tier II watersheds, etc.) 

6-G Closed drilling systems on zero-discharge drilling pads on which all drilling and hydraulic 

fracturing fluids, chemicals, and liquid wastes are collected and stored in steel tanks that 

provide superior primary containment to holding ponds are a best management practice. 

Vacuum trucks could be used to handle on-site runoff during drilling and well completion 

(see Chapter 4). 

6-H Maryland should require an invasive species management plan of industry prior to any 

drilling operations. Such a plan should include, at the minimum: 

6-H.1 A description of water sources to be used to fill any impoundment, including 

analysis of any invasive species that might be present at the withdrawal site but 

absent from the watershed where the impoundment will be located. 

6-H.2 Water withdrawal equipment should be power-washed and rinsed with clean water 

before leaving the withdrawal site. 

6-I Maryland should prohibit the discharging of any previously impounded water back into a 

natural water body, thus reducing the chance for the introduction of invasive species and 

short-term elevated thermal regimes in streams. 

6-J Wherever possible, existing roads should be used in MSGD. Where new roads are 

required, PA DCNR recommendations could be adopted: 

6-J.1 Use materials and designs (e.g., crowning, elimination of ditches, etc.) that 

encourage sheet flow as the preferred drainage method for any new construction or 

upgrade of existing gravel roadways. 

6-J.2 Where stream crossings are unavoidable, use bridges or arched culverts to 

minimize disturbance of streambeds. 

6-J.3 Promote the use of geotextiles as a way of reducing rutting and maintaining subbase stability. 

6-J.4 Open trenches within streams should be avoided in favor of using directional 

boring techniques. 

6-K In general, during road and pad construction a combination of BMPs should be used to 

reduce sediment and erosion, recognizing that additional protective measures might be 

necessary during wet times of the year (primarily late winter and early spring). 

G. Literature cited 

Alexander, R. B., E. W. Boyer, R. A. Smith, G. E. Schwarz, and R. B. Moore. 2007. The role of headwater 

streams in downstream water quality. Journal of the American Water Resources Association 43:41-

59. 

API. 2011. Practices for Mitigating Surface Impacts Associated with Hydraulic Fracturing. API Guidance 

Document HF3. American Petroleum Institute, Washington, DC. 
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Benda, L., K. Andras, D. Miller, and P. Bigelow. 2004. Confluence effects in rivers: Interactions of basin 

scale, network geometry, and disturbance regimes. Water Resources Research 40. 

Bilton, D. T. 2001. Dispersal in Freshwater Invertebrates. Annual Review of Ecology and Systematics 

32:159-181. 

Booth, D. B., D. Hartley, and R. Jackson. 2002. Forest cover, impervious-surface area, and the mitigation 

of stormwater impacts. Journal of the American Water Resources Association 38:835-845. 

Brooks, B. W., J. P. Grover, and D. L. Roelke. 2001. An emerging threat to inland waters. Environmental 

Toxicology and Chemistry 30:1955-1964. 

Bunn, S. E., P. M. Davies, and T. D. Mosisch. 1999. Ecosystem measures of river health and their response 

to riparian and catchment degradation. Freshwater Biology 41:333-345. 

Eaton, J. G., and R. M. Scheller. 1996. Effects of climate warming on fish thermal habitat in streams of the 

United States. Limnology and Oceanography 41:1109-1115. 

Elmore, A. J., J. P. Julian, S. M. Guinn, and M. C. Fitzpatrick. in review. Potential stream density in midAtlantic U.S. watersheds. Plos One. 

Fagan, W. F. 2002. Connectivity, fragmentation, and extinction risk in dendritic metapopulations. Ecology 

83:3243-3249. 

Hedrick, L., S. Welsh, J. Anderson, L.-S. Lin, Y. Chen, and X. Wei. 2010. Response of benthic 

macroinvertebrate communities to highway construction in an Appalachian watershed. 

Hydrobiologia 641:115-131. 

Henley, W. F., M. A. Patterson, R. J. Neves, and A. D. Lemly. 2010. Effects of Sedimentation and 

Turbidity on Lotic Food Webs: A Concise Review for Natural Resource Managers. Reviews in 

Fisheries Science 8. 

Hilderbrand, R. H. 2003. The roles of carrying capacity, immigration, and population synchrony on 

persistence of stream-resident cutthroat trout. Biological Conservation 110:257-266. 

Hilderbrand, R. H., and J. L. Kershner. 2000. Conserving inland cutthroat trout in small streams: how much 

stream is enough? North American Journal of Fisheries Management 20:513-520. 

Hudy, M., T. M. Thieling, N. Gillespie, and E. P. Smith. 2008. Distribution, status, and land use 

characteristics of subwatersheds within the native range of brook trout in the Eastern United States. 

North American Journal of Fisheries Management 28:1069-1085. 

Ingersoll, C. G., D. R. Mount, D. D. Gulley, T. W. Lapoint, and H. L. Bergman. 1990. Effects of PH, 

Aluminum, and Calcium on survival and growth of eggs and fry of brook trout (Salvelinus 

fontinalis). Canadian Journal of Fisheries and Aquatic Sciences 47:1580-1592. 

Julian, J. P., A. J. Elmore, and S. M. Guinn. 2012. Channel head locations in forested watersheds across the 

mid-Atlantic United States: A physiographic analysis. Geomorphology 177-178:194-203. 

Kemp, P., D. Sear, A. Collins, P. Naden, and I. Jones. 2011. The impacts of fine sediment on riverine fish. 

Hydrological Processes 25:1800-1821. 

King, G. E. 2012. Estimating frac risk and improving frac performance in unconventional gas and oil 

wells.in Society of Petroleum Engineers Hydraulic Fracturing Conference, The Woodlands, TX. 

Koehn, S. W., and A. Hairston-Strang. 2009. Forestry Best Management Practices in Maryland: 

Implementation and Effectiveness for Protection of Water Resources. Maryland Department of 

Natural Resources Forest Service. 

Leivestad, G. 1982. Physiological effects of acid stress in fish. Pages 157-164 in R. E. Johnson, editor. 

Acid rain/fisheries. American Fisheries Society, Bethesda, MD. 

Lien, A. M., and W. J. Manner. 2010. The Marcellus shale: resources for stakeholders in the Upper 

Delaware watershed region. Pinchot Institute for Conservation. 

Likens, G. E., and F. H. Bormann. 1974. Linkages between terrestrial and aquatic ecosystems. BioScience 

24:447-456. 

Lopez, C. B., E. B. Jewett, Q. Dortch, B. T. Walton, and H. K. Hudnell. 2008. Scientific assessment of 

freshwater harmful algal blooms. Joint Subcommittee on Ocean Science and Technology, 

Washington, D. C. 

Lowe, W. H., and G. E. Likens. 2005. Moving headwater streams to the head of the class. BioScience 

55:196-197. 
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McCormic, J. H., B. R. Jones, and K. E. Hokanson. 1972. Effects of temperature on growth and survival of 

young brook trout, Salvelinus fontinalis. Journal of the Fisheries Research Board of Canada 

29:1107-&. 

MDNR. 2010. Maryland Biological Stream Survey. 

Merriam, E. R., J. T. Petty, J. G. T. Merovich, J. B. Fulton, and M. P. Stranger. 2011. Additive effects of 

mining and residential development on stream conditions in a central Appalachian watershed. 

Journal of the North American Benthological Society 30:399-418. 

Meyer, J. L., D. L. Strayer, J. B. Wallace, S. L. Eggert, G. S. Helfman, and N. E. Leonard. 2007. The 

contribution of headwater streams to biodiversity in river networks. Journal of the American Water 

Resources Association 43:86-103. 

Mount, D. R., C. G. Ingersoll, D. D. Gulley, J. D. Fernandez, T. W. Lapoint, and H. L. Bergman. 1988. 

Effect of long-term exposure to acid, aluminum, and low calcium on adult brook trout (Salvelinus 

fontinalis) .1. Survival, growth, fecundity, and progeny survival. Canadian Journal of Fisheries and 

Aquatic Sciences 45:1623-1632. 

NYSDEC. 2011. Revised draft supplemental generic environmental impact statement on the oil, gas, and 

solution mining regulatory program. Albany, NY. 

Oke, T. R., J. M. Crowther, K. G. McNaughton, J. L. Monteith, and B. Gardiner. 1989. The 

Micrometeorology of the Urban Forest [and Discussion]. Philosophical Transactions of the Royal 

Society of London 324:335-349. 

Palmer, M. A., C. M. Swan, K. Nelson, P. Silver, and R. Alvestad. 2000. Streambed landscapes: evidence 

that stream invertebrates respond to the type and spatial arrangement of patches. landscape ecology 

15:563-576. 

PADCNR. 2011. Guidelines for administrating oil and gas activity on state forest lands. Commonwealth of 

Pennsylvania Department of Conservation and Natural Resources Bureau of Forestry. 

Petty, J. T., J. B. Fulton, M. P. Strager, J. G. T. Merovich, J. M. Stiles, and P. F. Ziemkiewicz. 2010. 

Landscape indicators and thresholds of stream ecological impairment in an intensively mined 

Appalachian watershed. Journal of the North American Benthological Society 29:1292-1309. 

Renner, R. 2009. Salt-loving algae wipe out fish in Appalachian stream. Environmental Science & 

Technology 10.1021/es903354w. 

Rice, S. P., R. I. Ferguson, and T. B. Hoey. 2006. Tributary control of physical heterogeneity and 

biological diversity at river confluences. Canadian Journal of Fisheries and Aquatic Sciences 

63:2553-2566. 

Rice, S. P., M. T. Greenwood, and C. B. Joyce. 2001. Tributaries, sediment sources, and the longitudinal 

organisation of macroinvertebrate fauna along river systems. Canadian Journal of Fisheries and 

Aquatic Sciences 58:824-840. 

Scheetz, B. E., and S. M. Bloser. 2008. Environmentally Sensitive Maintenance Practices for Unpaved 

Roads: Sediment Reduction Study. Center for Dirt and Gravel Road Studies, Penn State University. 

Stranko, S. A., R. H. Hilderbrand, R. P. Morgan, M. W. Staley, A. J. Becker, A. Roseberry-Lincoln, E. S. 

Perry, and P. T. Jacobson. 2008. Brook trout declines with land cover and temperature changes in 

Maryland. North American Journal of Fisheries Management 28:1223-1232. 

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Tarboton, D. G., and M. E. Baker. 2008. Towards an algebra for Terrain-Based Flow Analysis.in N. J. 

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the Natural Environment: Innovations in GIS. CRC Press, Florida. 

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responses of aquatic invertebrates to land cover gradients. Ecological Indicators 9:556-567. 
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Utz, R. M., R. H. Hilderbrand, and R. L. Raesly. 2010. Regional differences in patterns of fish species loss 

with changing land use. Biological Conservation 143:688-699. 

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urban stream syndrome: current knowledge and the search for a cure. Journal of the North 

American Benthological Society 24:706-723. 
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7. Protecting public safety1

Modern shale gas development is an industrial activity that involves handling of very large 

quantities of hazardous or toxic chemicals, hydraulic fracturing fluids, and wastewaters (“brines”) 

at outdoor sites often located in remote or rural areas. It is very common for most of these 

materials to be transported by trucks for considerable distances on public roads to the drilling 

sites. Further, like any other outdoor activities, these drilling sites are exposed to extreme weather 

and environmental conditions (e.g., snowstorms, rainstorms, floods, windstorms, freezing 

conditions, etc.) that not only make working at such sites difficult, but also elevate the risk of 

accidents, spills, or leakages away from a particular site. Unless such spills are prevented and/or 

quickly contained, surface water or groundwater contamination may result, which can expose 

humans or ecosystems to toxic chemicals. For this reason, New York State has concluded that 

shale gas well pads and all associated on-site infrastructure should be treated like other industrial 

facilities. The first step in protecting public safety from some of the primary hazards associated 

with industrial facilities is siting such facilities as far away as possible from homes, businesses, 

public buildings, or places with high levels of recreational activity (e.g., hiking trails, parks, picnic 

areas, etc.). This can be achieved through the use of setbacks and careful permitting in the vicinity 

of parks and other recreational resources (see Chapter 8). Secondly, employing best management 

practices in well construction (e.g., casing and cementing) in order to ensure wellbore integrity 

and isolation are important steps that must be used to control migration of hydrocarbons, brines, or 

hydraulic fracturing fluids into groundwater, causing pollution of underground drinking water 

supplies (see Chapter 3). As discussed below, security measures such as adequate signage, 

lighting, fencing and supervision that are appropriate to other industrial facilities should be 

required to ensure that shale gas development is conducted in as safe a manner as possible 

(NYSDEC 2011). 

 

A. Spill prevention and emergency response 

The prevention and containment of spills involving hazardous or toxic chemicals used in the 

completion process, hydraulic fracturing fluids, or wastewaters at a well site—or during transit to 

or from a well site—is a very important component of providing protection of public safety, as 

well as the surrounding environment. As noted previously in Chapters 1 and 4, a best practice in 

spill prevention and protection of public safety in general is the development of a site-specific, 

emergency response plan (ERP) that describes specifically in writing how a particular operator 

will respond to different emergencies (e.g., spills) that may occur during each phase of shale gas 

development at a particular site (or off-site) and across the operators’ many related facilities (e.g., 

multiple wells and water impoundments). The procedures outlined in an ERP are intended to 

provide for the protection of lives (workers and the public at large), property (both on-site and offsite), and the environment, through appropriate advance planning, safety training, and coordinated 

deployment of company and community assets. In addition to addressing spill prevention and 

clean-up procedures, an ERP would also logically include procedures for protecting the public 

from fires, explosions, or blow-outs that could occur on a well pad2. While the names of such 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. and Andrew J. Elmore, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532) 2

 West Virginia Horizontal Well Act. 

http://www.legis.state.wv.us/Bill_Status/bills_text.cfm?billdoc=hb401%20enr.htm&yr=2011&sesstype=4X&i=401 
K.N. Eshleman & A.J. Elmore Chapter 7

7-2 

plans vary from state to state, documents describing emergency preparedness are required or 

proposed in all states in our review (and are advocated by API). The ERP proposed for shale gas 

development in New York State would have, at a minimum, the following elements (NYSDEC 

2011): 

• Identity of a knowledgeable and qualified individual with the authority to respond to 

emergency situations and implement the ERP 

• Site name, type, location (including a copy of 71⁄2 minute USGS map), and operator 

information 

• Emergency notification and reporting (including a list of emergency contact numbers for 

the area in which the well site is located; and appropriate regulatory office), equipment, 

key personnel, first responders, hospitals, and evacuation plan 

• Identification and evaluation of potential release, fire and explosion hazards 

• Description of release, fire, and explosion prevention procedures and equipment 

• Implementation plans for shut down, containment, and disposal 

• Site training, exercises, drills, and meeting logs 

In addition, as required by PADEP, a Prevention, Preparedness, and Contingency (PPC) Plan in 

Pennsylvania (similar to an ERP in New York) must include a list of all chemicals or additives 

used and the different wastes generated by hydraulic fracturing (and approximate quantities of 

each material and the method of storage on-site), as well as MSDS data, toxicological data, and 

waste chemical properties. A more comprehensive and standardized PPC Plan would also include: 

(1) assigning 9-1-1 addresses to sites to aid in emergency responses; (2) providing geographic 

positioning system (GPS) coordinates for access roads and well pad sites; and (3) distributing PPC 

Plans to the appropriate county emergency management coordinator so that emergency responders 

would have immediate access to MSDS information in the event of an actual emergency 

(Marcellus Shale Advisory Commission 2011). Another best practice related to implementation of 

an ERP is that inspectors be given 24-hour notice before any major operation occurs at a particular 

well site (i.e., cementing, hydraulic fracturing, drilling, flaring) (STRONGER 2011). 

As is the policy in most states that we reviewed, an ERP should be developed in Maryland and 

submitted to the appropriate state regulatory authority as part of the well permit application 

process. The ERP could also be part of an overall site-specific safety plan developed by an 

operator to address the full gamut of public safety issues involving such topics as site security and 

off-site transportation of materials. In addition to development and implementation of an ERP, 

there are many other BMPs that are critical for spill prevention and containment. Most of these are 

primarily used for protecting water resources (both surface water and groundwater) and were 

discussed in more detail in Chapter 4. 

Effective implementation of an ERP in the event of an actual emergency requires specialized 

teams of emergency responders, appropriately trained in specific well pad emergencies, public 

safety, and methods isolating and securing an incident site. Each county should have at least one 

specialized team of emergency responders available at all times to respond to an emergency. The 

emergency responders should leave control of well blow-outs, fires or contaminant releases to 

professional, operator-trained experts utilizing equipment staged in a manner to provide a timely 

response to emergencies. It is important that each well operator maintain all necessary equipment 

to respond to various types of emergencies in a satisfactory operating condition and on-site 

throughout the drilling and completing phases of the operation. 
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compressors, tanks, impoundments, and separators, to restrict public access; and (2) use of safety 

or security guards to further control access (particularly important during active drilling and 

completion phases of an operation). As in Ohio, duplicate keys to all locks should be provided to 

the regulatory agency and to local emergency responders upon request. 

C. Transportation planning 

Transportation planning is an important consideration in shale gas development due to the need 

for moving large quantities of heavy equipment, chemicals, water, and wastewater either to or 

from various sites distributed throughout a particular region. We discuss transportation planning in 

Chapter 9 in the context of protecting quality of life and aesthetics in predominantly rural western 

Maryland, but it should be kept in mind that transportation planning must also address risks to 

public safety—especially those specifically posed by frequent truck transport of materials on rural 

public roadways and bridges that in many cases were neither designed nor constructed for such 

purposes. 

The natural gas industry faces significant logistical challenges associated with transporting and 

storing the tremendous volumes of sand, pipe, water, and other materials that are necessary to drill 

and complete a Marcellus shale gas well. According to the Governor’s Marcellus Shale Advisory 

Commission (2011), the maximum distance to effectively serve a well head in Pennsylvania is 75 

miles, especially due to the steep terrain found in many of Pennsylvania’s drilling locations. The 

closer a drilling company can get to areas where it can store the vast quantities of materials 

required for drilling a well, the better the efficiency of the drilling operation. Railroads, already in 

place and operational, could provide an alternative system for effectively and efficiently receiving, 

storing, and trans-loading commodities to well heads in Pennsylvania and throughout the 

Marcellus shale region. The railroads (and rail terminals) provide an added benefit of reducing the 

need to develop a staging area on forest land or other vacant land within a 50- to 75-mile radius. 

Nevertheless, even with the benefit of rail transportation, there would still exist the need for trucks 

to move material and equipment from a rail terminal to the well pads (Marcellus Shale Advisory 

Commission 2011), so the impact of using rail transportation on truck transportation may not be 

that great. Further, while western Maryland is obviously home to a major CSX rail yard at 

Cumberland, the closest actual rail terminal to the region is in Hagerstown—60-100 miles away—

perhaps too far away for railroads to play a major role in staging MSGD operations. The proximity 

of the Cumberland rail yard to a major interstate highway (I-68) that bisects western Maryland 

would seemingly make this an ideal location for an MSGD staging area, however. If Maryland 

decides to move ahead with MSGD, the state might consider investing public funds in new 

terminal facilities in western Maryland to support the activity, provide incentives for private 

financing, or both (as has been done in Pennsylvania through Rail Freight and Rail Transportation 

Assistance Programs). 

With respect to truck transportation, there are obvious risks to public safety (injury, death) 

associated with accidents involving additional traffic onto roads and bridges, plus additional risks 

associated with exposure to spilled hazardous chemicals, fires, or explosions resulting from such 

accidents. As recommended for Pennsylvania, we believe it is reasonable to expect the appropriate 

state transportation authorities to calculate, evaluate, and address the major impacts of additional 

truck traffic on the road and highway system prior to shale gas development occurring in an 

undeveloped part of the state (Marcellus Shale Advisory Commission 2011). At the same time, 

counties and municipalities should also undertake an inventory and structural evaluation of 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

7-5 

locally-owned bridges currently exempt from federally mandated inspections (typically 8 ft to 20 

ft) to ensure that these structures are capable of safely handling the additional traffic (and loads) 

associated with shale gas development. While this recommendation was made for Pennsylvania, 

we believe that the same type of analysis could and should be done for western Maryland. Where 

the road network or bridges are deemed inadequate for supporting the additional traffic, the road 

system (including inadequate bridges) should be upgraded to support such traffic prior to shale gas 

development occurring or such traffic should not be permitted on these roads. With respect to 

movement of heavy equipment on state highways, we also agree with the recommendation that the 

state should be responsible for establishing a protocol to allow for emergency transport of such 

equipment during off-hour periods (evenings, nights, and weekends) in cases where there is an 

immediate need of the equipment (Marcellus Shale Advisory Commission 2011). The protocol 

would be similar to how ‘wide loads’ are presently transported in the state of Maryland and would 

thus require cooperation and coordination with the state police who assume primary responsibility 

for the highway system. 

D. Key recommendations 

3-A The first line of defense in protecting public safety is designing MSGD operations in a way 

that maintains separation between MSGD infrastructure (including transportation routes) 

and the public. 

3-A.1 Facilities should be sited as far away as possible from homes, businesses, public 

buildings, or places with high levels of recreational activity (e.g., hiking trails, 

parks, picnic areas, etc.) (see Chapter 9 also). 

3-A.2 Best management practices in well construction (e.g., casing and cementing) should 

be followed to ensure wellbore integrity and isolation (see Chapter 3). 

3-A.3 Proper monitoring and pre-development assessment are important steps to limit the 

migration of hydrocarbons, brines, or hydraulic fracturing fluids into groundwater, 

causing pollution of underground drinking water supplies and to enable rapid 

detection in the event of migration (see Chapters 1 and 4). 

3-B MSGD applicants should be required to develop site-specific, emergency response plans 

(ERP) that describes in detail how a particular operator will respond to different 

emergencies that may occur during each phase of shale gas development at sites, or 

transportation routes between sites, permitted for MSGD. 

3-B.1 The ERP must include many types of standard information, including the names 

and contact information for first responders, and location (including GPS 

coordinates) of MSGD sites. 

3-B.2 The ERP must include variations on standard responses demonstrating sensitivity 

to weather, time of day, time of year, and the particular geography of sites (e.g., 

topographic and soil conditions). 

3-B.3 The ERP must also include a list of all chemicals or additives used, expected 

wastes generated by hydraulic fracturing, approximate quantities of each material, 

the method of storage on-site, MSDS for each substance, toxicological data, and 

waste chemical properties. 

3-C Best management practices implemented to avoid emergencies should include: 
K.N. Eshleman & A.J. Elmore Chapter 7

7-6 

3-C.1 Adequate perimeter fencing (at least a 6 ft high chained link or equivalent), gates 

(with keyed locks), and signage in place around drill rigs, engines, compressors, 

tanks, impoundments, and separators, to restrict public access. 

3-C.2 Use of safety or security guards to further control access (particularly important 

during active drilling and completion phases of an operation). 

3-C.3 Duplicate keys to all locks should be provided to the regulatory agency and to local 

emergency responders. 

3-D Maryland’s Department of Transportation should calculate, evaluate, and address the major 

impacts of additional truck traffic on the road and highway system prior to the state 

permitting MSGD. 

3-D.1 Counties and municipalities should also undertake an inventory and structural 

evaluation of locally-owned bridges currently exempt from federally mandated 

inspections to ensure that these structures are capable of safely handling the 

additional traffic (and loads) associated with MSGD. 

3-D.2 The state should establish a protocol to allow for emergency transport of heavy or 

oversized equipment during off-hour periods (evenings, nights, and weekends). 

E. Literature cited 

Marcellus Shale Advisory Commission. 2011. [Pennsylvania] Governor's Marcellus Shale Advisory 

Commission Report. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

STRONGER. 2011. Ohio Hydraulic Fracturing State Review. Oklahoma City, OK: State Review of Oil 

and Natural Gas Environmental Regulations, Inc. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

8-1

8. Protecting cultural, historical, and recreational resources1

Western Maryland (Allegany and Garrett County) contains a plethora of cultural, historical and 

recreational resources. Many types of sites (e.g., national and state historic sites, heritage areas, 

local historic districts, state parks, wildlife management areas, wildlands, etc.) would be at risk of 

impairment, either through physical, visual, auditory, or olfactory degradation. In addition to their 

intrinsic value, some of these resources, such as historical landmarks or unique natural landscape 

features (lakes, waterfalls, etc.), draw considerable tourism, generating revenue for local 

communities and the state of Maryland. In 2011, nearly $6M in sales tax was collected through 

combined tourism-related sales in these two counties.2

 The local job market depends in part on 

tourism, accounting for over $50M in tourism-related salaries for the two-county area in 20083,4. 

A decline in the quality or quantity of resources that attract tourism would potentially limit further 

economic development in this area. Disturbance associated with site preparation work, well 

drilling activities, truck traffic, and operation of heavy equipment—unless successfully avoided or 

mitigated for—could negatively impact the enjoyment of natural areas for hunting, fishing, hiking, 

boating, and other recreational activities. Finally, natural areas might also be impacted through 

inadvertent introductions of invasive species or losses of natural biological/landscape biodiversity 

(see Chapters 5 and 6). 

A. Identification of sites 

Protection of cultural, historical, and recreational resources must begin with identification of sites 

that would be adversely affected by Marcellus shale gas development. However, many of these 

resources (e.g., national and state historic properties) are virtually unknown and are typically 

unmapped. In cases like this, New York State requires identification of all sites that are eligible for 

inclusion on state and national registers of historic properties, or are included on the state 

inventory, to ensure that they receive special consideration, protecting them from disturbance or 

impairment. Many state and federal databases exist to provide such information, but the 

inventoried data are typically not transmitted to users in the form of a digital map. New York has 

actually mapped out its visually sensitive resource areas and has proposed that applicants submit a 

visual resource mitigation plan as part of the permit application process (NYSDEC 2011). In 

western Maryland, there are six listed items on the National Trust for Historic Preservation, plus 

52 sites in Allegany County and 23 sites in Garrett County listed on the National Register of 

Historic Properties.5

 Moreover, there are literally hundreds of sites in these counties that are listed 

on the state inventory including historic properties, local historic districts (Cumberland and 

Frostburg), historic cemeteries and monuments, roadside historical markers, and a state heritage 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. and Andrew J. Elmore, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532) 2

 Maryland Tourism Development Board. 2008. Annual report, available online at: 

http://www.visitmaryland.org/AboutMDTourism/Pages/TourismNewsAndReports.aspx. 3

 Department of Business and Economic Development. 2011. Maryland Tourism Fastfacts. Available online at: 

http://visitmaryland.org/AboutMDTourism/Documents/Annual_Report_2011.pdf. 4

 Additional information on the economic impact of Maryland State Parks can be found in the 2010 Maryland State 

Parks Economic impact & Visitor Study, accessed at the following URL on February 13, 2013: 

http://www.dnr.maryland.gov/publiclands/pdfs/economicimpactstudy2010.pdf 5

 http://www.mht.maryland.gov/nr/NRPickCounty.html. 
K.N. Eshleman & A.J. Elmore (2013) Chapter 8 

8-2 

area (Mountain Maryland Gateway to the West Heritage Area that includes the towns of Accident, 

Deer Park, Friendsville, Grantsville, Kitzmiller, Loch Lynn Heights, Mountain Lake Park, 

Oakland, McHenry, and Bloomington plus scenic byways that connect these towns in Garrett 

County) (not shown). Given the large number of sites that could be impacted in these two 

counties, best practice would be for operators to consult with the Maryland Historical Trust 

(MHT) within the Maryland Department of Planning and other county and local historic 

preservation offices during the planning and permit application process to ensure that no eligible 

or existing cultural or historical sites would be potentially disturbed or impaired by any aspect of 

shale gas development. 

Western Maryland also contains extensive public recreational resources that will require 

identification and mapping, including: a national historical park, a national scenic trail, state 

parks, state forests, state forest trails, state wildlife management areas, natural areas, wildlands, a 

wild river, a national byway, and two state scenic byways. Most of these state and federal 

recreational resources and important natural areas are reasonably well known and mapped in 

Maryland. On an areal basis, state forest land (118,099 acres) is by far the largest public 

recreational space in the two-county region, covering 21% of the total land area. Wildlife 

management areas cover 17,809 acres (2.6%) and state parks cover 10,203 acres (1.5%). 

Confronted with a similar level of diversity in the types of resources that exist, Pennsylvania 

DCNR Bureau of Forestry recommends that any constraints mapping done by gas drilling 

companies operating in the Pennsylvania state forests should be done in close consultation with 

local stakeholders who typically have the best knowledge of these resources. In Maryland, 

regardless of whether or not a proposed operation would be located on state or federal land, best 

practice would require close consultation with local governments, state park and forest officials, 

national park managers, and wildlife managers who are familiar with the resources that could be 

impaired by shale gas development. To facilitate this planning activity, we have provided a list of 

the major public recreational and natural resource areas that could be impacted by shale gas 

development in western Maryland (Table 8-1, Figure 8-1, Figure 8-2). 

B. Setback requirements and mitigation 

To avoid disturbances or impairment of major cultural and historical resources, New York State 

handles proposed oil and gas drilling near these sites on a case-by-case basis. A variety of 

mitigative actions can be required including: (1) visual screening of drilling operations; (2) 

setback requirements greater than minimums for private homes (100 ft) and public buildings or 

areas (150 ft); (3) restriction on times of operation (e.g., avoid tourist season, museum hours, 

whitewater release dates, opening days for hunting and fishing, etc.); and (4) landscaping 

reclamation requirements. In New York, many of these mitigative actions are presently added as 

conditions to drilling permits (NYSDEC 2011). Other mitigative BMPs that have been proposed 

in New York include: relocation of MSGD infrastructure found damaging by local residents or 

resource managers, use of camouflage or disguise to reduce the impact of MSGD infrastructure, 

maintaining low facility profiles, downsizing the scale of a project, using alternative technologies, 

using non-reflective materials, and controlling off-site migration of lighting (NYSDEC 2011). 

With respect to state forest recreational areas, Pennsylvania DCNR Bureau of Forestry requires a 

300 ft. setback from any state forest picnic area, trail, road of historic value, tree plantation, 

overlook, vista, fire tower site, or existing right of way; this setback also affords additional 

protection of public safety through conflict avoidance. The Bureau of Forestry also relies on local 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

8-3

knowledge of cultural sites, recreational trails, trailheads, high use areas, viewsheds, vistas, and 

high aesthetic areas during the permitting process with a goal of avoiding areas of (or providing 

increased setbacks from) concentrated recreational activity and developed recreational sites when 

permitting gas related infrastructure (PADCNR 2011). In the Pennsylvania state forests, an 

important criterion in site selection for drilling pads is the degree to which locations can provide 

natural vegetative or topographic screening (PADCNR 2011). Additionally, API recommends that 

setbacks be increased to take into account prevailing winds and topography; in New York, sites 

are assessed for their archeological importance (NYSDEC 2011). 

Table 8-1. Public recreational resources in Allegany and Garrett County, Maryland. 

Name of Resource Administered by County 

Chesapeake and Ohio Canal National Historical Park National Park Service Allegany 

Potomac Heritage National Scenic Trail National Park Service Allegany 

Historic National Road U.S. Dept. of Transportation Allegany, Garrett 

Dan’s Mountain State Park Maryland Dept. of Natural Resources Allegany 

Rocky Gap State Park Maryland Dept. of Natural Resources Allegany 

Big Run State Park Maryland Dept. of Natural Resources Garrett 

Casselman River Bridge State Park Maryland Dept. of Natural Resources Garrett 

Deep Creek Lake State Park Maryland Dept. of Natural Resources Garrett 

Deep Creek Lake Natural Resources Management 

Area 

Maryland Dept. of Natural Resources Garrett 

Herrington Manor State Park Maryland Dept. of Natural Resources Garrett 

New Germany State Park Maryland Dept. of Natural Resources Garrett 

Swallow Falls State Park Maryland Dept. of Natural Resources Garrett 

Youghiogheny River State Park Maryland Dept. of Natural Resources Garrett 

Green Ridge State Forest Maryland Dept. of Natural Resources Allegany 

Garrett State Forest Maryland Dept. of Natural Resources Garrett 

Potomac State Forest Maryland Dept. of Natural Resources Garrett 

Savage River State Forest Maryland Dept. of Natural Resources Garrett 

Bell Grove Wildlife Management Area Maryland Dept. of Natural Resources Allegany 

Billmeyer Wildlife Management Area Maryland Dept. of Natural Resources Allegany 

Dan’s Mountain Wildlife Management Area Maryland Dept. of Natural Resources Allegany 

Sideling Hill Wildlife Management Area Maryland Dept. of Natural Resources Allegany 

Warrior Mountain Wildlife Management Area Maryland Dept. of Natural Resources Allegany 

Mt. Nebo Wildlife Management Area Maryland Dept. of Natural Resources Garrett 

Deep Run Wildland Maryland Dept. of Natural Resources Allegany 

Maple Run Wildland Maryland Dept. of Natural Resources Allegany 

Potomac Bends Wildland Maryland Dept. of Natural Resources Allegany 

Rocky Gap Wildland Maryland Dept. of Natural Resources Allegany 

Bear Pen Wildland Maryland Dept. of Natural Resources Garrett 

High Rock Wildland Maryland Dept. of Natural Resources Garrett 

Middle Fork Wildland Maryland Dept. of Natural Resources Garrett 

Savage Mountain Wildland Maryland Dept. of Natural Resources Garrett 

Savage Ravines Wildland Maryland Dept. of Natural Resources Garrett 

South Savage Wildland Maryland Dept. of Natural Resources Garrett 

Youghiogheny State Wild River Maryland Dept. of Natural Resources Garrett 

Mountain Maryland Scenic Byway State Highway Administration Garrett 

Chesapeake and Ohio Canal Scenic Byway State Highway Administration Allegany 
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Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

8-5

With respect to state forest recreational areas, Pennsylvania DCNR Bureau of Forestry requires a 

300 ft setback from any state forest picnic area, trail, road of historic value, tree plantation, 

overlook, vista, fire tower site, or existing right of way; this setback also affords additional 

protection of public safety through conflict avoidance. The Bureau of Forestry also relies on local 

knowledge of cultural sites, recreational trails, trailheads, high use areas, viewsheds, vistas, and 

high aesthetic areas during the permitting process with a goal of avoiding areas of (or providing 

increased setbacks from) concentrated recreational activity and developed recreational sites when 

permitting gas related infrastructure (PADCNR 2011). In the Pennsylvania state forests, an 

important criterion in site selection for drilling pads is the degree to which locations can provide 

natural vegetative or topographic screening (PADCNR 2011). Additionally, API recommends that 

setbacks be increased to take into account prevailing winds and topography; in New York, sites 

are assessed for their archeological importance (NYSDEC 2011). 

Figure 8-3. Many western Maryland recreational sites, such as this section of the C&O canal southeast of 

Cumberland, draw tourism from eastern portions of the state as well as throughout the Midwest.

Knowledge of potential conflicts with cultural, historical and recreational resources is presumably 

afforded through good communication between MSGD operators, local governments, and state 

regulatory and management agencies. Certainly a first step is the identification of the location of 

cultural and recreational resources potentially impacted by MSGD. However, this should be 

followed up with an in-depth analysis of the ways in which the local and visiting population uses 

these resources. API recommends that operators communicate with land owners and/or surface 

users concerning activities planned for a particular site and provide information on the measures to 

be taken for safety, protection of the environment, and minimization of impacts to surface uses. 

The goals of any interactions should be for transparency and increasing the flow of timely and 

relevant information to surface owners, users, and other stakeholders. As recommended in 

Pennsylvania (Ubinger et al. 2010), Maryland might consider developing a standardized 

stakeholder process that could be implemented as part of comprehensive planning strategy; the 

goal of such a process would be to engage stakeholders and the community in the most effective 

ways possible, while allowing the permit review process to be expedited. 

C. Key recommendations 

8-A Applicants for drilling permits should be required to consult with Maryland Historical 

Trust during the planning and permit application process to identify all eligible or existing 

cultural or historical sites in the vicinity of proposed MSGD activity (including all drill pad 

sites, gas pipelines, roads, and transportation routes to and from MSGD facilities). 

8-B Regardless of whether or not a proposed operation would be located on state or federal 

land, best practice would require close consultation with local governments, state park and 
K.N. Eshleman & A.J. Elmore (2013) Chapter 8 

8-6 

forest officials, national park managers, and wildlife managers who are familiar with the 

resources that could be impaired by shale gas development. 

8-C Applicants should be required to submit a visual resource mitigation plan as part of the 

permit application process based on site-specific assessment (i.e., viewshed analysis). 

8-D Site selection for drilling pads in Maryland should be locations that can provide natural 

vegetative or topographic screening. 

8-E Siting of well pads, or the routing of MSGD-related truck traffic, near high use recreation 

areas should be avoided if possible. 

8-F Maryland should impose a minimum 300 ft setback from all cultural and historical sites, 

state and federal parks, trails, wildlife management areas, natural areas, wildlands, scenic 

and wild rivers, and scenic byways to protect the region’s most important cultural, 

historical, recreational, and ecological resources. Setback considerations should include 

high use areas, noise and visual impacts, and public safety concerns. 

8-G The calculation of setback distances should consider prevailing winds, topography, and 

viewsheds, and repeatable formulas for calculating setbacks should be established. 

8-H Mitigative techniques, such as the use of visual screens, sound barriers, camouflage, and 

landscaping near cultural and historical sites, as well as restricting the times of gas 

development operations, should be required to minimize disturbances and conflicts with 

recreational activities in areas adjacent to gas development zones. 

8-I Any permitted shale gas development activities in the vicinity of public recreational 

sites—including state forests—should be timed so as to avoid periods of peak recreational 

activity (e.g., holiday weekends, first day of trout season, spring and fall hunting seasons, 

whitewater release dates, etc.). Maryland DNR should collect and provide data to help 

inform peak activity times. 

D. Literature cited 

Marcellus Shale Advisory Commission. 2011. [Pennsylvania] Governor's Marcellus Shale Advisory 

Commission Report. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 

PA DCNR. 2011. Guidelines for Administering Oil and Gas Activity on State Forest Lands. 

Commonwealth of Pennsylvania Department of Conservation and Natural Resources Bureau of 

Forestry. 

Ubinger, J. W., J. J. Walliser, C. Hall, and R. Oltmanns. 2010. Developing the Marcellus Shale: 

Environmental Policy and Planning Recommendations for the Development of the Marcellus Shale 

Play in Pennsylvania. Harrisburg, PA: Pennsylvania Environmental Council. 
 Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

9-1

9. Protecting quality of life and aesthetic values1

 The overall quality of life and aesthetic values in the two western Maryland counties derives in 

large measure from the mostly undeveloped rural mountainous landscape dominated by forests 

interspersed with agricultural lands and relatively small towns. The few cities in western 

Maryland have changed relatively little over recent decades despite explosive population and 

exurban growth to other parts of the state. The relatively slow-paced way of life, minimal 

automobile traffic, and associated amenities are attractive features of the area for residents and 

visitors alike (Wainger and Price 2004, Chancellor et al. 2011). As discussed in Chapter 8, the 

quality of life is also significantly enhanced by the recreational opportunities afforded by the 

extensive state and federal public lands that exist in both Allegany and Garrett County. Hiking, 

biking, hunting, fishing, swimming, and boating are just some of the recreational activities that 

are afforded through access to the state parks, forests, wildlife management areas, and wildlands 

in the region (Boller et al. 2010). While providing economic benefits to the region, shale gas 

development in western Maryland clearly has the potential to negatively impact the area’s 

quality of life and aesthetic character through altered land use, increased traffic (particularly 

heavy truck traffic), noise pollution, visual and light pollution, and by creating conflicts with 

ordinary community activities that would not exist in its absence. The purpose of this chapter is 

to provide recommendations of best practices that could significantly mitigate for these negative 

impacts. Note that many other practices that address quality of life and aesthetic issues (e.g., 

constraints mapping for well siting; setback requirements for protecting cultural, historical, and 

recreational resources, and public safety) were previously addressed in Chapters 1, 8, and 7, 

respectively. 

A. Hours of operation 

New York State has proposed that shale gas development activities be conducted in a way that 

avoids peak traffic hours, school bus hours, museum hours, community events, tourist periods, 

and overnight quiet periods (NYSDEC 2011). Similarly, as discussed in Chapter 8, Pennsylvania 

DCNR Bureau of Forestry (PA DCNR 2011) mandates that any permitted shale gas development 

activities in Pennsylvania state forests be timed to avoid periods of peak recreational activity 

(e.g., holiday weekends, first day of trout season, whitewater release dates, spring and fall 

hunting seasons, etc.). Considering the potential intensity of truck transport during the drilling 

and completion process, a comprehensive plan to protect the quality of life and aesthetic values 

in western Maryland should include multiple synergistic strategies to limit gas-development 

related disturbance. Similar to best practices proposed by New York State and employed by 

Pennsylvania state forests, Maryland could restrict hours and times of operation to avoid or 

minimize the greatest conflicts, but this practice by itself is unlikely to be sufficient. Best 

management would employ thoughtful siting and visual screens, and rely on restrictions on hours 

of operation to mediate the most disruptive activities (e.g., during well completion). As discussed 

in Chapter 1, practices that would be generally effective at reducing conflicts would be: (1) siting 

well pads away from populated areas (especially those with schools and other regularly-visited 

 

1

 Chapter co-authors: Andrew J. Elmore, Ph.D., and Keith N. Eshleman, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532). 
K.N. Eshleman & A.J. Elmore (2013) Chapter 9 

9-2

public buildings); (2) siting well pads and associated facilities in industrial parks designed and 

zoned for this type of industrial activity; (3) siting well pads in close proximity to major 

interstate highways and exit ramps designed to efficiently handle round-the-clock transportation; 

and (4) reducing truck traffic associated with water, chemical, and wastewater hauling (e.g., 

through use of temporary pipelines). Used in combination with such siting criteria, restrictions 

on hours and times of operation (based on input from the public) would likely provide significant 

additional mitigation of the most problematic conflicts. 

B. Noise control 

Many studies illustrate a link between exposure to noise and negative effects on public health. 

Noise may severely impair quality of life (disrupt sleep, interfere with speech intelligibility), or 

possibly give rise to both social and psychological problems (Bodin et al. 2008). Excessive noise 

also has a broader environmental impact, for instance it can reduce optimal habitat area for 

critical species or alter their behavior (Yong 2008) (also discussed in Chapter 5). Several states 

and API provide specific best management practices to deal with issues of noise control. 

Colorado has established maximum permissible noise levels for oil and gas operations at well 

sites and gas production facilities. In Colorado, operations involving a pipeline or gas facility 

installation or maintenance, the use of a drilling rig, completion rig, workover rig, or well 

stimulation are all subject to the maximum permissible noise levels for industrial zones. In the 

hours between 7:00 a.m. and the 7:00 p.m., the noise levels of different land uses surrounding an 

industrial zone may be increased 10 db(A) for a period not to exceed 15 minutes in any one-hour 

period.2

 New York also has established techniques for assessing, mitigating, and evaluating noise 

impacts and specific sound levels and characteristics of proposed or existing facilities (NYSDEC 

2011). API (API 2011) and these two states have also identified specific BMPs that can be 

employed for mitigating noise impacts through: (1) careful siting of facilities—distance, 

direction, timing, and topography are the primary considerations in mitigating noise impacts 

from hydraulic fracturing and trucking operations (API 2011); (2) requirement for ambient noise 

level determination prior to operations; (3) placement of walls, artificial sound barriers, or 

evergreen buffers between sources and receptors (i.e., especially around well pads and 

compressor stations) (API 2011); (4) use of noise reducing equipment (e.g., mufflers) on flares, 

drill rig engines, compressor motors, and other equipment (API 2011); and (5) use of electric 

motors in place of diesel-powered equipment if feasible. We recommend that Maryland require 

as part of the permitting process: (1) the enforcement of minimum distances between well pads 

and surrounding homes, businesses, and heavily-used recreational facilities to reduce noise as 

much as possible; (2) require ambient noise level determination prior to operations; (3) 

construction of artificial sound barriers where natural noise attenuation would be inadequate; (4) 

equipping all motors and engines with appropriate mufflers; and (5) requiring electric motors in 

place of diesel-powered equipment for any operations within 3,000 ft of any occupied building. 

No drilling or compressor stations should be permitted within 1,000 ft of a residence. 

C. Road impacts and transportation planning 

Assessing the environmental impact of gas development activities should include an assessment 

of the impact of vehicle traffic moving into, through, and out of sensitive areas via the existing 

road network. Such an analysis must determine: (1) which segments of the network are 

 

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K.N. Eshleman & A.J. Elmore (2013) Chapter 9 

9-4

designed to achieve the following: (1) maximize efficient driving; (2) route vehicles onto roads 

and across bridges specifically designed to carry heavy truck loads on a repetitive basis; (3) 

ensure public safety; (4) avoid peak and sensitive traffic hours; (5) ensure that all trucks are DOT 

compliant; (6) coordinate with highway departments and emergency responders; (7) 

upgrade/improve roads as needed; (8) inform the public of any necessary detours; (9) utilize 

flowlines to reduce truck traffic (if feasible and cost effective); and (10) assure adequate off-road 

parking at well site and delivery areas (API 2011). Further, as proposed in New York, any 

deviation from the plan, detours or closures, must be done with advanced public notice. Roaduse agreements should also be established between operators and municipalities to ensure public 

safety and provide a mechanism for addressing road damages attributable to shale gas 

development in a timely way.

Existing roads should be utilized wherever feasible; if new roads are needed, however, potential 

impacts should be considered along with landowner recommendations, consideration for 

historical and cultural resources, and a mitigation strategy to prevent erosion and protect 

environmentally-sensitive areas. Both API (API 2009) and Pennsylvania DCNR (PADCNR 

2011) provide specific recommendations for the design and construction of new roads in rural 

landscapes. While roads should be designed and constructed in ways appropriate for their 

intended use, it is recommended that construction crews consider using the PA DNCR for 

construction of permanent non-paved roads to address potential environmental impacts, control 

erosion, and avoid damage to environmentally sensitive areas (PADCNR 2011). 

D. Visual pollution/viewsheds 

As discussed in Chapter 8 in the 

context of protecting cultural, 

historical and recreational resources, 

there are two types of mitigative 

techniques that are appropriate for 

addressing visual pollution and 

minimizing degradation of visually 

sensitive resources in general. The 

first type of technique involves the 

use of viewshed analysis to help 

carefully site well pads and 

associated infrastructure at locations 

that are least visible from heavily 

used roads, overlooks, or public 

recreational facilities. The second 

type of mitigation involves the use of 

visual screens, camouflages, paint 

schemes, evergreen buffers, and 

landscaping techniques to obscure drilling equipment and shale gas development activities from 

view as much as possible. We recommend use of both types of mitigative techniques to minimize 

degradation of western Maryland viewsheds by shale gas development activities as much as 

possible. It should be emphasized that because well drilling and completion operations that 

employ large amounts of heavy (and, in some cases, three stories tall) equipment on-site are 

Figure 9-2: Drill rigs must be lit at night to facilitate 24-hr operations, 

however, during the production phase artificial lighting might be 

eliminated.
 Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

9-5

temporary in nature, the most severe degradation of visually-sensitive resources occurs during 

periods of maximum development activity. We believe that removal of major equipment alone 

would in some cases contribute significantly to restoring these natural viewsheds. In other cases, 

careful land reclamation practices (e.g., revegetation of well pads, planting of evergreen screens 

around permanent gas infrastructure, etc.) would provide additional benefits (see Chapter 4). 

Light pollution has the added potential (above and beyond general impacts to viewsheds) to pose 

significant direct and indirect effects on the quality of life and aesthetic values in western 

Maryland (Figure 9-2). Indirect effects of light pollution were covered in Chapter 5, and take the 

form of the different ways in which artificial lighting can influence wildlife and biological 

diversity more generally. Artificial lighting causes direct effects on the quality of life and 

aesthetic values by being a distraction while driving on primary and secondary roads, obscuring 

dark night skies, and reducing the rural aesthetic qualities of the region. Many visitors to western 

Maryland frequent campgrounds and other state facilities, and expect dark night skies as part of 

their experience. Maryland could put an emphasis on preserving these conditions. Similar to 

what was discussed in Chapter 5, the primary BMPs for reducing the impact of artificial light 

aim to reduce the amount of lighting used, keep lights low and directed down on the work site as 

much as possible, and increase the use of low-pressure sodium lights relative to other types of 

lighting. Most polluting are lamps with a strong blue emission, like metal halide and white lightemitting diodes (LEDs) (Falchi et al. 2011). Following these guidelines, Maryland could take 

steps to reduce the amount and nature (color) of artificial lighting used during MSGD. It should 

also be noted that the light required at different stages of MSGD can vary substantially; while 

high light levels might be required during drilling and well completion, during production 

artificial lighting could be reduced or eliminated altogether (after addressing security concerns.) 

E. Key recommendations 

9-A Well-pad siting should consider the multiple factors that influence the quality of life and 

aesthetics of rural life in western Maryland (e.g., location of existing infrastructure, 

traffic loads on existing roads, etc.) 

9-A.1 Site well pads away from occupied buildings (e.g., dwellings, churches, 

businesses, schools, hospitals, and recreational facilities) 

9-A.2 Site well pads and associated facilities in industrial parks (either new or existing) 

designed and zoned for this type of industrial activity 

9-A.3 Site well pads in close proximity to major interstate highways and exit ramps 

designed to efficiently handle round-the-clock transportation 

9-A.4 Reduce truck traffic associated with water hauling through use of temporary 

pipelines where possible. 

9-B Each of the counties in western Maryland should revisit noise regulations and 

enforcement policies and confirm they are appropriate for this industrial activity. 

9-C No drilling or compressor stations should be permitted within 1,000 ft of an occupied 

building. 

9-D Require electric motors (in place of diesel-powered equipment) for any operations within 

3,000 ft. of any occupied building 
K.N. Eshleman & A.J. Elmore (2013) Chapter 9 

9-6

9-D.1 Encourage electric motors in place of diesel-powered equipment wherever 

possible. 

9-D.2 Restrict hours and times of operation to avoid or minimize the greatest conflicts 

between the public and MSGD. 

9-D.3 Require ambient noise level determination prior to operations. 

9-D.4 Require construction of artificial sound barriers where natural noise attenuation 

would be inadequate. 

9-D.5 Equip all motors and engines with appropriate mufflers. 

9-E All permit applicants should develop and submit a detailed transportation plan for 

approval by the regulatory authority prior to conducting any site development, drilling, 

well work over, or well completion activities 

9-E.1 The approval process for the transportation plan should allow for adequate 

comment by the public, state transportation agencies, and county roads 

departments. 

9-F It is recommended that new road construction follows PADCNR guidelines for 

construction of permanent non-paved roads to address potential environmental impacts, 

offset erosion, and avoid damage to environmentally sensitive areas. 

9-G We recommend the use of viewshed analysis to help determine the best location for 

MSGD-related infrastructure as well as to determine what mitigative techniques would be 

appropriate. 

9-H We recommend use of mitigative techniques (e.g., the use of visual screens, camouflages, 

paint schemes, evergreen buffers, and landscaping techniques) to minimize degradation 

of western Maryland viewsheds by MSGD. 

F. Literature cited 

API. 2009. Environmental Protection for Onshore Oil and Gas Production Operations and Leases (API 

RP-51R, First Edition). Washington, DC: American Petroleum Institute Publishing Services. 

API. 2011. Practices for mitigating surface impacts associated with hydraulic fracturing (API Guidance 

Document HF3, First Edition). Washington, DC: American Petroleum Institute Publishing 

Services. 

Bodin, T., M. Albin, J. Ardo, E. Stroh, P. Ostergren, and J. Bjork. 2008. Road traffic noise and 

hypertension: results from a cross-sectional public health survey in southern Sweden. New 

Scientist 197:33-35. 

Boller, F., M. Hunziker, M. Conedera, H. Elsasser, and P. Krebs. 2010. Fascinating Remoteness: The 

Dilemma of Hiking Tourism Development in Peripheral Mountain Areas Results of a Case Study 

in Southern Switzerland. Mountain Research and Development 30:320-331. 

Chancellor, C., C. P. S. Yu, and S. T. Cole. 2011. Exploring Quality of Life Perceptions in Rural 

Midwestern (USA) Communities: an Application of the Core-Periphery Concept in a Tourism 

Development Context. International Journal of Tourism Research 13:496-507. 

NYSDEC. 2011. Revised Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas, 

and Solution Mining Regulatory Program. 
 Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

9-7

PADCNR. 2011. Guidelines for Administering Oil and Gas Activity on State Forest Lands. 

Commonwealth of Pennsylvania Department of Conservation and Natural Resources Bureau of 

Forestry. 

Wainger, L. A., and E. W. Price. 2004. Evaluating quality of life, economic vulnerabilities, and drivers of 

ecosystem change. Environmental Monitoring and Assessment 94:69-84. 

Yong, E. 2008. City songbirds change their tune. New Scientist 197:33-35. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

10-1 

10. Protecting agriculture and grazing1

After forested land, agricultural land is the second largest contributing land cover in Allegany and 

Garrett Counties on an areal basis, covering 15.6% (108,420 acres) of these two counties. In 2007, 

the most recent year for which data are published, it is estimated that Allegany County had 302 

farms covering a land area of 36,343 acres2, while Garrett County had 677 farms covering 95,514 

acres.3 The value of all agricultural product sales in the two counties was estimated as $3.16M and 

$27.73M, respectively. Farms in these two counties are typically small family operations, with the 

average farm covering 121 acres in Allegany and 141 acres in Garrett County4. While many types 

of county-level data from the National Agricultural Statistics Service are not published to protect 

economically sensitive information, major crops produced in these two counties include corn for 

grain, corn for silage, soybeans, winter wheat, other hay, barley, and vegetables, in addition to 

milk, cattle and calves, sheep, hogs, and poultry. In addition to the economic value of crops and 

other agricultural production, agriculture also contributes aesthetically to the quality of life and 

cultural fabric of rural western Maryland as discussed in Chapter 9. While important in this regard, 

it must be noted that agricultural production in both western Maryland counties is dwarfed by 

production in many other counties in the state. For example, Carroll County which has about 

142,000 acres in farmland as of 2007 (roughly the same acreage as Allegany and Garrett Counties 

combined) had agricultural product sales that were about a factor of three greater ($87.4M).5

 This 

difference is consistent with the generally low fertility soils and cool climate of western Maryland. 

Nonetheless, as an important economic activity in the region and as a component of Maryland’s 

general effort to maintain farming activities throughout the state, contributing to overall quality of 

life, we believe that there are some best practices that can protect both cropland and grazing land 

from negative impacts of shale gas development. 

One recent study of farm animals in six states (Pennsylvania, New York, Ohio, Colorado, Texas, 

Louisiana) suggested increased mortality rates in livestock and companion animals (i.e., dogs and 

cats) living close to active gas-drilling operations (Oswald and Bamberger 2012), with several 

caveats associated with the lack of controls due to the case study aspect of the survey (Thompson 

2012). Although chemicals can be volatized (e.g., by impoundment aerators) and misted into the 

air creating an inhalation exposure pathway, the most common source of toxicity exposure was 

likely via contaminated water. Pathways of exposure included, for example, spills of hydraulic 

fracturing fluids, tears in the liners of wastewater impoundments (which we do not recommend but 

have been used in PA), and spreading of wastewater on roads to reduced dust and ice followed by 

animals licking their paws after crossing the roads (again, the spreading of wastewater on roads is 

not recommended for Maryland). Health impacts ranged from neurological to sudden death with 

the most common effects being reproductive. Animals affected include cows, horses, goats, 

 

1

 Chapter co-authors: Keith N. Eshleman, Ph.D. and Andrew J. Elmore, Ph.D. (both at: Appalachian Laboratory, 

University of Maryland Center for Environmental Science, Frostburg, MD 21532). 2

 Allegany County 2010 Agricultural Profile, Maryland Department of Agriculture. 

http://www.mda.state.md.us/on_web/ag_links/countyag.php#allegany. 3

 Garrett County 2010 Agricultural Profile, Maryland Department of Agriculture. 

http://www.mda.state.md.us/on_web/ag_links/countyag.php#garrett. 4

 The difference between agricultural land area and farm area in these counties is likely due to the presence of 

woodlots on many of these farms. In other words, some of the farm area is actually mapped as forest cover. 5

 Carroll County 2010 Agricultural Profile, Maryland Department of Agriculture. 

http://www.mda.state.md.us/on_web/ag_links/countyag.php#garrett. 
K.N. Eshleman & A.J. Elmore Chapter 10 

10-2 

llamas, chickens, dogs, cats, and koi. Because the movement of farm animals is confined they may 

experience higher cumulative exposure than wildlife with less restricted mobility. However, 

photographic evidence has been reported of dead and dying songbirds, deer, frogs, and 

salamanders (Oswald and Bamberger 2012). 

A. Protection of prime farmland 

Prime farmland is an official designation used by U.S. Department of Agriculture to define land 

that has the best combination of physical and chemical characteristics for producing important 

agricultural crops. Prime soils have the following inherent characteristics: a minimum amount of 

surface rocks, low susceptibility to erosion and have not had been excessively eroded in the past, a 

favorable pH, an acceptable level of content of salt and sodium, water and air permeability, and 

are not subject to prolonged saturation. They also have the following related qualities: have nearly 

level to gently sloping topography, and rarely or never flood during the growing season.6 Fewer 

than 2% of western Maryland soils are considered prime soils7, and 71% are considered class VI 

or VII, designating them as suitable for planting of permanent pasture, trees, or reserved for 

wildlife management and recreation8. As recommended by Lien and Manner (2010), we agree that 

soil conditions at sites being considered for shale gas development be evaluated as part of the 

planning process; prime agricultural soils and prime farmland should generally not be disturbed 

for well pad siting, road construction, or any ancillary gas development activities. Further, highly 

erodible soils should also be identified as part of the planning process and appropriate best 

practices should be employed to prevent erosion and sedimentation problems in developing these 

areas (see Chapter 4). 

Some agricultural lands in western Maryland are already protected to some extent by the Maryland 

Agricultural Land Preservation Foundation (MALPF). MALPF—which protects agricultural land 

in Maryland through the use of perpetual easements—was created by the Maryland General 

Assembly in 1977 and is housed within the Maryland Department of Agriculture (MDA). Prior to 

2007, applications for easements were only accepted from landowners in designated Agricultural 

Preservation Districts. Easements may be donated or purchased with a goal of providing for the 

perpetual production of local food and fiber. Agricultural land easements in western Maryland are 

displayed in Figure 10-1 and comprise about 4.3% of the agricultural land in the two counties. 

The text in the current standard deed of easement found at the MALPF website reads as follows: 

“No rights-of-way, easements, oil, gas or mineral leases, or other similar servitude may be 

conveyed, or permitted to be established on the land for any commercial, industrial or residential 

use, without the Grantee's express written permission.”9

 Thus, any surface uses of the land for 

shale gas development without the Grantee’s (i.e., state of Maryland’s) written permission would 

appear to expressly violate the protective status granted under MALPF. 

 

6

 http://www.md.nrcs.usda.gov/technical/nritext.html. 

7

 Ibid. 

8

 Land Capability Classification. Agriculture Handbook No. 210. Soil Conservation Service. U.S. Department of 

Agriculture. Issued September 1961. Reprinted January, 1973 9

 Current Standard Deed of Easement, para. II.A.2, pp. 3-4, Maryland Agricultural Land Preservation Foundation; 

http://www.malpf.info/laws.html 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

10-3 

Figure 10-1. Agricultural land is generally confined to floodplains (Allegany County) and the Appalachian Plateau 

(Garrett County). Maryland Agricultural Land Preservation Foundation (MALPF) agricultural easements (sometimes 

located within agricultural districts) protect land from non-agricultural uses and are administered by Maryland 

Department of Agriculture. Rural Legacy Area Properties have multiple goals, including to protect economies based 

on farming and forestry, and are administered by the Department of Natural Resources.

A second mechanism through which agricultural land has been protected is Maryland’s Rural 

Legacy Program, which was enacted by the General Assembly in 1997, and has dedicated over 

$210 million to preserve 68,675 acres of valuable farmland, forests, and natural areas throughout 

the state10. In western Maryland, 62,747 acres have been identified as Rural Legacy Areas, a 

subset of this area has been protected through conservation easements (Figure 10-1). The Rural 

Legacy Program's goals are to establish greenbelts of forests and farms around rural communities 

to preserve their cultural heritage and sense of place, and critical habitat for native plant and 

wildlife species. Relevant to prime farmland, the Rural Legacy Program also aims to support 

natural resource economies such as farming, forestry, tourism and outdoor recreation. Similar to 

MALPF conservation easements, subsurface activities on Rural Legacy properties are prohibited 

without the Grantees’ approval and require the Grantee to consider whether the impact would be 

destructive of the conservation attributes the easements were designed to protect. In Garret 

County, the Bear Creek Rural Legacy Area overlays the Accident gas storage dome, and was 

established by the Maryland Department of Natural Resources in collaboration with Garrett 

County to protect farms with severed or leased mineral rights with the understanding that gas 

storage activities would continue to take place on lands encumbered with Rural Legacy easements, 

provided that such storage activities do not unduly compromise the natural and working resources 

the Area were established to protect. In Allegany County, the Mountain Ridge Rural Legacy Area 

is delineated around 10,163 acres of existing protected lands that may be further connected and 

 

10 http://www.dnr.state.md.us/land/rurallegacy/12thAnniversary.asp 
K.N. Eshleman & A.J. Elmore Chapter 10 

10-4 

consolidated, forming a greenway potentially linking ridgetops in West Virginia with 

Pennsylvania, as well as westward into the Allegheny Plateau. 

Protected lands throughout western Maryland have clearly been established with consideration of 

agriculture and prime soils as an objective. Therefore, restricting MSGD so as to preserve prime 

soils and agricultural lands could be achieved by enforcing MALPF and Rural Legacy Area 

easements throughout western Maryland. From our reading of the MALPF and Rural Legacy 

Program websites, it appears this would just require that Maryland not approve any MSGD in 

these areas. With respect to other non-protected agricultural lands where shale gas development 

might be permitted, some of the best practices proposed by New York State would provide an 

appropriate level of protection, of agriculture and grazing, namely (NYSDEC 2011): 

• Well pads, infrastructure, roads, and utility corridors should generally be sited along field 

edges, thus avoiding bisection of fields. 

• Topsoil should be stockpiled during site development activities, covered during storage, 

and redistributed back onto agricultural land as part of the land reclamation process. 

• In active agricultural areas, operators must: (1) keep drill cuttings and topsoil separate; (2) 

remove any drilling muds from fields; (3) avoid soil compaction; and (4) fence in active 

pasture areas (alternately fence livestock out of gas development areas). 

B. Key recommendations 

10-A Soil conditions at sites being considered for shale gas development should be evaluated as 

part of the planning process. 

10-B Prime agricultural soils and prime farmland protected by Maryland’s existing land 

easement programs should not be disturbed for well pad siting, road construction, or any 

ancillary gas development activities. 

10-C Highly erodible soils should also be identified as part of the planning process and 

appropriate best practices employed to prevent erosion and sedimentation problems in 

developing these areas (see Chapter 4). 

10-D Well pads, infrastructure, roads, and utility corridors should generally be sited along field 

edges, thus avoiding bisection of fields. 

10-E Topsoil should be stockpiled during site development activities, covered during storage, 

redistributed back onto agricultural land as part of the land reclamation process, and soil 

compaction should be avoided at all times. 

10-F Operators must fence livestock out of gas development areas. 

C. Literature cited 

Lien, A. M., and W. J. Manner. 2010. The Marcellus shale: resources for stakeholders in the 

Upper Delaware watershed region. Pinchot Institute for Conservation. 

NYSDEC. 2011. Revised draft supplemental generic environmental impact statement on the oil, 

gas, and solution mining regulatory program. Albany, NY. 

Oswald, R., and M. Bamberger. 2012. Impacts of gas drilling on human and animal health. New 

Solutions 22:51-77. 
Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

10-5 

Thompson, H. 2012. Fracking boom spurs environmental audit. Nature 485:556-557.