# Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland

Keith N. Eshleman & Andrew Elmore (PIs) Appalachian Laboratory University of Maryland Cente r for Environmental Science Frostburg, MD 21532

Final Report submitted to: Maryland Department of the Environment Baltimore, MD

February 18, 2013ii 

### Acknowledgments
We solicited and received the help of quite a few people during the comple tion 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, Carne gie 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 secti ons of the report, so they are listed as chapter co-authors . We thank the following indivi duals for providing us with data: Scott Bearer, Deborah Carpenter, Jennifer Chadwick-Moore, Kevin Coyne, Lynn Davidson, Gregory Day, Dan Feller, Dave Foreman, Mike Garner, J ohn Grace, Jeff Halka, Kara Hawkins, Jaron Hawkins, Greg Hildreth, Zoe Johnson, Catherine M cCall, 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 a nd performed many of the geographic analyses on which our recommendations ar e based. Robert Hilderbr and 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 envir onmental 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 aqui fers 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 coordi nation, 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 precurs or 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 technique s 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: setb acks and restrictions ..................................................................... 4-3 B. Monitoring of water resources prior t o, during, and followi ng development ....................... 4-6 C. Water pollution, stormwater management , and erosion and sediment control .................... 4-8 D. Water withdrawals .......................................................................................................... ..... 4-15 E. Comprehensive basin-scale wa ter 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 ................................................................ 4-22iv I. Identification of chemicals ................................................................................................ .... 4-23 J. Drilling and drilling wastes ............................................................................................... ... 4-23 K. On site management of produ ced waters and wastewaters ................................................. 4-24 L. Management of produced water (incl uding 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 radio active materials (NORM) ............................................................ 4-31 Q. Key recommendations ........................................................................................................ . 4-32 R. Literature cited ........................................................................................................... .......... 4-33 Chapter 5. Protecting terrestr ial 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 habi tat, 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 road s, 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 tran sportation planning ........................................................................... 9-2 D. Visual pollution/viewsheds ................................................................................................ .. 9-4 E. Key recommendations ........................................................................................................ ... 9-5 F. Literature cited ........................................................................................................... ............ 9-6v Chapter 10. Protecting agriculture and grazing ....................................................................... 10-1 A. Protection of prime farmland .............................................................................................. 10-2 B. Key recommendations ........................................................................................................ . 10-4 C. Literature cited ........................................................................................................... .......... 10-4vi 

### List of Acronyms and Abbreviations

AMD acid mine drainage

API American Petroleum Institute

BCF billion cubic feet

bhp-hr brake horsepower-hour

BioNET Biodiversity C onservation 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

CO 2 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 Na tural Resources (MD)

EAF environmental assessment formvii ELAP Environmental Labora tory 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

km 2 square kilometersviii 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 St ream Chemistry Survey

MWD measurement while drilling

NAAQS National Ambient Air Quality Standard

NESHAP National Emission Standard s for Hazardous Air Pollutants

NORM naturally occurring radioactive materials

NO x nitrous oxide

NPDES National Pollutant Discharge Elimination Systemix NRC National Research Council

NSPS New Source Performance Standards

NWI National Wetlands Inventory

NYSDEC New York State Department of Environmental Conservation

O 3 ozone (photochemical smog)

ONRW outstanding nationa l 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

PM 2.5 fine particulate matter (< 2.5 μ m)

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 assura nce/quality control

RAIN River Alert Information Network

RCRA Resource Conservation and Recovery Act

RGGI Regional Greenhouse Gas Initiative

RP recommended practicex 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 Natura l 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, natura lly-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 logxi VOC volatile organic compound

WOC wait on cement

WQS water quality standards

WSSC Wetlands of Special State Concern

WVDEP West Virginia Department of Environmental ProtectionRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

i 

### Summary of key findings and major recommendations 1
The Marcellus shale formation underlying numerous A ppalachian states is c onsidered 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 “unconventiona l” development that includes both modern horizontal drilling and high volume hydraulic fracturing technologies. Unlike neighboring Pennsylvania that participated fully in the in itial boom in explorati on and production between 2005 and 2009 (drilling has occu rred extensively both on pr ivate and public lands in Pennsylvania), Maryland (with a significantly sm aller resource) has chosen to stay on the sidelines with an unofficial moratorium on unconventional Marcellus shale gas development (MSGD) while it studies the less ons from other states, determines whether development can go forward safely, and evaluates it options. The pres ent 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 Mary land’s environment, natural resources, and public safety should the state decide to move fo rward 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 allowe d us to gain an important visu al perspective of the operations, practices, and challenges involve d in conducting MSGD. Wherever possible, we also reviewed the scientific literature to evaluate the proven e ffectiveness of different pr actices, but the lack of comprehensive, data-driven studies of the impact s of MSGD both on-site and off-site present a significant impediment to recommending best practi ces on the basis of this criterion alone. For this reason, we have explicitly chosen to id entify and recommend specific BMPs that—mostly on the basis of our professiona l judgment—would provide as much protection of Maryland’s natural, cultural, historical and recreational re sources; the environment; and public safety as can reasonably be provided while al lowing 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 stat e’s borders) and that a signifi cant portion of these “costs” will be borne by local commun ities. Heavy truck traffic on local roads, noise and odors emanating from drilling sites, conflicts with out door recreation, diminished tourism, reduced biodiversity, and deterioration of air and water quality are some ex amples of the types of impacts that are likely even under the best of circum stances. While difficult to quantify in economic terms, these “costs” will ideally be greatly ou tweighed by the benefits of increased economic activity—otherwise it is very di fficult 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 findi ngs and major recommendations

ii Maryland’s environment, natura l resources, and public safety. Th ere are a variety of types of resources and hazards—in some cases overlap ping—distributed across the western Maryland landscape that present im portant constraints on MSGD. For th is 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 activ ity in which well bores can be dr illed horizontally 8,000 ft from the well pad, it will often be possibl e to drill under the most valuab le and at-risk resources of western Maryland. This potential is enhanced th rough the use of multi-well pads that are capable of draining between one and two square miles ofthe target formation. Further, locating multiwell pads in dense clusters—with clusters spaced as far apart as is tec hnically feasible—makes maximum use of horizontal drilling technology a nd 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 BM Ps 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 regulati ons that pertains mostly to conventional oil and gas development, but the st ate 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 regulator y 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 fo rward 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 el sewhere. 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 recommendati ons is that the state should develop regulations to support the design and implementation of comprehensive drilling plans (CDPs) for MSGD. We envi sion a voluntary program similar to Colorado’s approach (and the program that has been used to develop th e Marcellus gas resource in Pennsylvania state forests), but one that provides strong incentive s for operators willing to consider this option. After identifying foreseeable oil and gas activi ties in a defined geographic area upfront, energy companies would work cooperativel y with other stakeholders (inc luding state natural resource agencies, counties, citizen groups, etc.) to develo p an integrated plan for efficiently exploiting the resource while minimizing impacts on commun ities, 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 industr ial activity into those areas wher e fewer of the most sensitive resources are “in harm’s way” and where new in frastructure needs (e.g., roads, pipelines) are lower. Logically, the first approved CDP woul d most likely result in permitting an area for drilling where major drilling hazards, risks to pub lic safety, and im pacts on sensitive ecological,Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

iii recreational, historical and cultu ral 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 c ould 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 an d off-site to document impacts (or non-impacts) would be used by the in dustry 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 im pacts 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 consider ation influencing the success of CDPs in Maryland would be careful site selection based on pre-developmen t environmental assessment for well pads and related infrastructure. A caref ul pre-drilling environmental assessment would include, at a minimum, an assessment of all existing data comb ined with two years of pre-drilling monitoring, including surface and groundwater testing, invent ories of rare, threatened and endangered species, and an assessment of th e 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 possi ble a defendable determination of liability. It is important to remember that western Ma ryland is a geographical ly small, rural, and mountainous landscape, offering re sidents a high quality of life, in part due to abundant biological, recreational, and cu ltural resources with exceptional value. Because of its mountainous landscape and history of coal mini ng, 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 conflic ts with existing land us es, and observe all ongoing efforts to conserve biol ogical diversity. Th roughout 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 we ll pads and related infrastructure.

One BMP we have highlighted throughout this report is the avoidan ce of underground voids, which can often be justified based on caves’ c onservation value for many rare threatened and endangered species. Additionally, complications fr om encountering a cave (or deep coal mine) during drilling can jeopardize the in tegrity 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 sc rutiny. A best practice for Maryland would be to avoid all underground voids by employing the best mapping a nd detection technologies and then applying additional setbacks when siting the borehole. Sim ilarly, there are several clusters of historic conventional gas wells throughout western Ma ryland. 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 ga s wells (vertical andK.N. Eshleman & A.J. Elmore ( 2013) Summary of key findi ngs 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 sa fely within relativel y close proximity to underground sources of drinking water, we r ecommend that Maryland prudently follow guidance from New York’s experience in regulating uncon ventional 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 fo r 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 curr ently below this thresh old. There is abundant scientific evidence that watershed impervious su rface area is a robust indicator of cumulative impacts to watershed structure and functioni ng. Secondly, we recommend imposing a “no-netloss-of-forest” requirement on MS GD. 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 im portant 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 dri ll rigs and compressor sta tions, limits on hours of drilling operations to avoid peak tourism peri ods (e.g., hunting season for white tail deer), and thoughtful truck traffic regulati on to reduce the impact of wate r 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 protect ed from the worst impacts. Sensible zoning ordinances and reasonable propert y 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 pa rties should be addresse d fully before drilling begins.

Our review of well engineering practices reve aled that the gas development industry has responded to pressure to reduce its environmenta l 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 effectivel y 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 pr ocessing and delivery to market , while the wastewater (i.e., “flowback”, brines) that is returned to the surf ace can be efficiently captured, contained, treated, and ultimately recycled (while things are rapi dly 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 ga s industry—has taken the le ad 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 “recomme nded practices” (RPs) which it communicates and shares with the industry. Many of these RP’s explicitly address problems inRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

v maintaining well integrity and pr ovide standards that have b een expressly adopted by state regulatory authorities. If Maryland decides to begin permitting MSGD, we recommend that any operator who proposes drilling in the state shoul d be required—at a minimum—to adopt API’s RPs and standards for well planning, well desi gn, 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 unconve ntional shale gas development. Maryland should require all operators to employ drilling, completion, and envi ronmental control technologies and practices that fully meet these evolving standard s and that are considered up-to-date.

The current BMP for handling drilling fluids, hydr aulic fracturing chemicals, wastewaters, and solid wastes on-site is through the use of a “clos ed-loop drilling system” in which all fluids are kept stored in watertight tanks that sit with in secondary containment on lined and bermed “zerodischarge” well pads that can pr ovide 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 cont ained. This type of dr illing system—if properly designed and operated—would be e xpected to provide the lowest risk of contaminant leakage off-site such as might occur during extreme w eather 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 site s in the same way that other “h otspots” are treated. Operators will need to employ both “active” an d “passive” stormwater management to effectively collect all water on a pad site over th e entire life of dril ling, completing, and producing operations to minimize soil erosion and downstream sedimentation (and avoid any inadvertent contaminant releases to the environment), although we e xplicitly recommend agai nst 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, trea ted, and either safely disposed of or reused. First of all, under no circumstances should Maryland allow discharge of any untreated or partially-treate d brine, or residuals from brine treatment facilities, into the waters of the state. To protect its water s upplies, Maryland should es tablish 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-s ite treatment by mobile units and immediate reuse for hydraulic fracturing at the sa me site (or at a nearby site). On-site water treatment and reuse would be expected to mi nimize overall freshwater use for MSGD and reduce the volume of waste, while dramatically decreasi ng truck transport and associated impacts across the region. Along these lines, the st ate should also explore the us e of non-potable water sources (e.g., acid mine drainage that repr esents a legacy of past coal mi ning practices in the region) as a way of supplementing needed wate r withdrawals from the region’s rivers and reservoirs. Finally, before permitting any development in the state, Maryland should carefully review the relevant regulations surrounding developmen t and use of underground injec tion 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 Ma rcellus Shale Gas Development in Maryland

1-1 

### 1. General, planning, and permitting BMPs 1
The Marcellus shale formation underlying numerous A ppalachian states is c onsidered 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” de velopment 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 ha s occurred extensively both on private and public lands in Pennsylvania), Maryland (with a significantly sm aller resource) chose to stay on the sidelines with an unofficial moratorium on unconventio nal Marcellus shale ga s development (MSGD) while it studies the lessons from other states , determines whether development can go forward safely, and evaluates it options 2 . The present study of best management practices (BMPs) for Marcellus shale gas development represents an e ffort to determine what actual practices would provide the maximum protection of Maryland’s environment, natura l 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 presen t (USEIA 2012). We foun d many estimates of the gas resource contained in the Marcellus form ation: (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 we re technically recoverable as of January 1, 2009 3 . Obviously, no one knows exactly how much gas exists within the Marcellus Shale underlying western Maryland, nor the value of the gas given uncerta inties 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 leas t 1,286 billion cubic feet (BCF) pr esent 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 peri od 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 realis tic, it is obvious from Pennsylvani a’s experience that very real economic benefits have been re alized from MSGD (including gene ration of $413M in lease sales on 139,000 acres of state forest from 2008-2010, plus $88M in royalties fr om gas production of about 250 wells) 4

. As part of our research, we have carefully re viewed the current regulations governing MSGD in five other states (Colorado, New York, Ohio, Pennsylvania, and We st 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 a nd 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 th e protection of terrestrial and a quatic habitat and biodiversity. Finally, we visited several well pads as part of some organized fiel d trips that allowed us to gain an important visual perspective of the ope rations, 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 impact s 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 we ll 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 du ring 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 drilli ng declines or ceases entirely as the commercially recoverable resource is depleted, the cycle enters the “bus t” phase in which population and jobs may quickly depart the area—leaving fewer people to suppor t the boomtown infrastructure. Communities where drilling-related benefits ha ve 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. Effectiv e 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 environm ental impacts from MSGD in western Maryland throughout the “boom-bust” cycle (and perhaps be yond) and that a significant portion of these “costs” will be borne by local communities. Hea vy truck traffic on local roads, noise and odors emanating from drilling sites, conflicts with out door recreation, diminished tourism, reduced biodiversity, and deterioration of air and water quality are some ex amples of the types of impacts that are likely even under the best of circum stances. While difficult to quantify in economic terms, these “costs” will ideally be greatly ou tweighed 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 term s) must be expected even if best practices are implemented, local ordinan ces and state gas devel opment regulations are carefully revised, and high standards of enforcem ent 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 th e basis of our profe ssional judgment—would provide as much protection of Ma ryland’s natural, cultural, histor ical and recreational resources; the environment; and public safety as can reas onably be provided while allowing MSGD to move forward. The hope is that through impl ementation of these BMPs many of the most egregious environmental impacts can be preven ted s (i.e., allowing th e external costs to effectively be “internalized”).Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

1-3 We have also concluded from our review a nd 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 no t observant of state boundaries. Since western Maryland (just two counties: Garr ett and Allegany) is a relative ly small “panhandle” sandwiched between Pennsylvania and West Virginia, in essen ce 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 polluta nts from other states impact Ma ryland air quality; traffic, the human environment, and the economics of sma ll towns in western Maryland are not immune from what is occurring in neighboring states). Th is 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 devel opment of the resource in neighbori ng 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 unconventiona l gas development from federal environmental regulation. In particular, we note that oil a nd gas wastes are exempt from hazardous waste provisions of the Resource Conservation and Re covery Act (RCRA)—based on a determination by the U.S. Environmental Protection Agency (USEPA) that existi ng 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 co mpanies 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 vol atile 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 properl y 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 de velopment, our recommendations are likely applicable to unconventional development of other shale formations such as the Utica as we ll. 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 MS GD should be used to identify (1) specific environmental conditions or features that woul d be expected to affect development of aK.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 tempor ary 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 perm it application process that would be used to: (1) identify the environmental reso urces (e.g., areas with high ecol ogical value, exceptional value waters, etc.) or features that w ould be relevant to de veloping a particular site; (2) identify the appropriate setbacks or restricti ons that would control development of a particular site; and (3) determine the environmental assessment activit ies or baseline mon itoring that would be necessary for development to go forward. In Ohio, the Department of Mineral Resources Management (DMRM) conducts a site review prio r to issuing a permit to evaluate any sitespecific conditions that might be attached to a pe rmit to drill in an urba n area (Ohio Legislative Service Commission 2010); Colorado Oil and Gas Conservation Commission (COGCC) maintains a website with maps of “Sensiti ve Wildlife Habitat” and “Restricted Surface Occupancy” areas that operators can use to determine whether a pr oposed oil or gas drilling site falls within such an area 5 . Maryland regulations governing o il and gas development require a reasonably extensive environmental assessment 6 , although it doesn’t ap pear to require any baseline monitoring activities as part of the process.

Pre-development activities are essential to en suring 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 ha bitats 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 dedica ted website. Once these data layers are made available, a prospective shale gas developer—prior to submitting a drilling application or comprehensive dr illing plan for review and appr oval—should be required to consult maps of (1) irreplaceable natural ar eas, (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 de termine 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 appli cable 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 ofunderground coal mining in the region, predevelopment environmental assessment should be conducted on a site-specific basis and include: (1) identification of all on-sit e 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/Applica tionsFormsandInstructions/Documents/www.mde.state. md.us/assets/document/permit/MDE-LMA -PER066.pdf for more details (web page accessed February 6, 2013)Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

1-5 and abandoned), orphaned gas or oil wells, caves, caverns, Karst f eatures, etc.; (2) identification of all ecological, recreational, hist orical, and cultural resources in the vicinity of a proposed site (includes well pad and all ancilla ry 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 year s of pre-development baseline data on underground sources of drinki ng water, downstream surface water, and both aquatic and terrestrial ecological resources. Several of these aspect s 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 th e following section.



### B. On-site and off-site monitoring On-site and off-site monitoring is an important aspect of MSGD that ha s not yet received the attention that the subject deserv es. 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. Dependi ng on the specific types and ways that data are collected, monitoring can clearly address:

• environmental regulation (ensuring complia nce with or documenting violations of standards and regulations);

• environmental remediation (establishi ng a benchmark for assessing damages and performing reclamation or restoration activities);

• environmental science (inc reasing process-level unders tanding, 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-des igned, 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) as sociated with MSGD through case studies could play an important role in gaining process-level unders tanding (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. Gi ven that the risks to surface wa ter quality from chemical or wastewater spills or releases ar e 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 publis hed. 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 ga s development (USDOE 2011) 9 . In fact, many of the BMPs that we have id entified in this report are based primarily on professional judgment rather than on systematic experimental testing w ith replication under a variety of field conditions. Our review revealed that relatively little mon itoring has been done to establish baseline resource condi tions prior to MSGD and subse quent 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 MS GD 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 un derway before this program was ever fully implemented (in fact, it ha s 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 benchmar k for assessing damages (or as defense from presumed liabili ty in the event that contamination is detected in the future). In Pennsylvania, for example, private water we lls located within 1,000 ft of a proposed gas well are tested before drilling as part of the pe rmitting process. Well monitoring in Pennsylvania showed post-drilling increases in bromide (Br) c oncentrations, suggesting that 3,000 ft is a more reasonable distance than the 1,000 ft that is currently required fo r both presumed responsibility and certified mail notification rela ted to Marcellus gas well drilling (Boyer et al. 2011). Few, if any, hydrogeologists would disagree with the co nclusion that sampling water wells within a 3,000 ft radius of a gas well is a pretty marginal groundwater monitoring progr am if the intent is to be able to detect a subsurface contaminant pl ume associated with a particular well integrity issue (especially in rural areas where the numbe r of water wells may be very low or zero).

Other resources that could be impacted by develo pment of a particular site (e.g., surface water quantity and quality, air quality, fo rest interior bird populations, etc.) have received even less attention, however. It is, ther efore, recommended that Maryland require as part of its permit application at le ast 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 a nd 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-specifi c monitoring plan for MSGD is well beyond the scope of this project, we can provide some r ough guidelines for what might const itute 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 part icular well pad; groundw ater 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 sampli ng of groundwater quality may suffice). A draft plan that we obt ained from Maryland DNR contains many of the elements that a solid, site-specific water and macr o-invertebrate monitoring plan w ould 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 Ma rcellus 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 imp acted by cumulative MSGD over the entire region (or within a portion of the region), so a monitori ng network will need to be established to address cumulative impacts both before and after develo pment 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 f unded; comparable surveys of surface water quality in specific western Maryland watersheds that are likely to experien ce 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 ex isting air quality monitoring station in the region is equipped with instrumentat ion to address primary MSGD imp acts (e.g., NOx, VOC, and fine particulate concentrations). While the design an d 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 c onducting for other purposes.



### C. Comprehensive drilling plans (CDP) One way of attempting to minimize some of th e most significant negative impacts associated with developing gas resources w ithin an area (and possibly mode rating 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 al so identifying the foreseeable oil and gas activities in a defined geogra phic area upfront, energy compan ies working cooperatively with other stakeholders (including stat e 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 rule 10 , gas operators in Colorado have the option of proposing a Compre hensive Drilling Plan (CDP) 11 that covers multiple drilling locations within an area as a way of addressing so me of these constraints; while voluntary, CDPs are definitely encouraged in Colorado and it ha s been concluded that the process would work better if operators would work together to deve lop 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 Battle ment Mesa area in Garfield County, CO—a community that is home for about 5,000 residents 12 . 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 speci al protection, a comprehensive gas development plan makes a lot of sense. Comprehensive pla nning 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, explora tion, environmental monitoring, drilling/fracking, gas transmission, transportation, planned mitigation of impacts, etc.).
12 See http://www.oilandga sbmps.org/resources/casestudies/battlement mesa.php (webpage accessed February 6,

2013)K.N. Eshl e

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—Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

1-9 gradually developing the appropriate experience over time th at plays and essential role in ensuring that development is conducted as safely as possible. In Pennsyl vania, 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 pr ogram in the state forests 13 , in addition to the large number of inspectors in PA DEP that enforces permit c onditions throughout the state. It is generally accepted that many of the problems that have o ccurred in Pennsylvania and elsewhere can be explained in part by the exce ssively rapid rate of MSGD be fore 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 pl ans involve significant interactions (“give and take”) be tween the energy companies, stat e 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 re gulatory structure and culture are sufficiently flexible to enable such an appro ach 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” (o r “compulsory integration” or “unitization”) 14

. With forced pooling, a gas company could force one or more entities wi th 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 prov iding greater protection of some specific surface resources overlying a portion of the unit). The prac tice 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 extrac t without causing undesira ble disturbances). Drilling companies have argued that forced pooling effectively enables more gas to be extracted from fewer well pads—thus reducing costs and e nvironmental 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 expl oitation. It is not clear to us whether forced pooling would be acceptable in Maryland, given the state’s legal a pproach to mineral righ ts; nonetheless, it is a topic that should be further examined.

13 Ibid., 5
14 Brigid Kenney (Maryland Depart ment of the Environment), person al communication (December 3, 2012).
15 Reported by ProPublica: http://www.propublica.or g/article/forced-poo ling-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 dr illing and hydraulic fracturing from multi-well pads are presently capable of draining at least on e or perhaps as much as two square miles of the target formation (see hypothetical example in Fi gure 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 a quatic 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 termsof 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 anal ysis suggests that—with careful and thoughtful planning (e.g., co-location of in frastructure 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 infrastruc ture 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 e xpected, it should be emphasized that disturbances of 1-2% of the la nd surface are quite low compared to other types of development (e.g., suburban resi dential, 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 Ma rcellus Shale Gas Development in Maryland

1-11 We also note that clustered well pad devel opment can only be expected to reduce surface impacts if operators are held to reasonable sp acing dimensions over time. In the Pennsylvania state forests, operators have ag reed to drill wells as reasonab ly prudent as possible—although not all leases had well spacing limitations. Newer le ases hold operators to a maximum number of well pad locations, or total disturba nce of a predefined acreage, whichever occurs first. In these leases, if an operator wishes to deviate from th e well pad numbers or acreage, a waiver and state forest approval is required (PADCNR 2011). Mini mizing the number and density of well pads through coordinated planning and c onsultation (i.e., a CDP), as we ll as utilization of existing rights of way, can greatly mitigate the cumulative impacts on the landscape (Marcellus Shale Advisory Commission 2011). Given th at 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 inf illing (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 ag encies can restrict shale gas development in an effort to provide some additional protection of the most sensitive ecological resources, water resources, personal property, pub lic property, and the health and safety of the public at large particularly in the event of an accident (e.g., pollutant spill, bl ow-out, etc.) during the conduct of shale gas development operations. How much protect ion (if any) these setbacks can provide can clearly be debated; many setbacks do not seem to be based on solid sc ientific reasoning or empirical data. Nevertheless, both industry and the state benefit when setbacks are clearly stated in statutes or regulations. Setb acks that are vague or that de pend on subjective site analysis introduce uncertainty into the decision-making process, leading to hi dden costs (redundant analyses at best and legal f ees at worst). Setbacks can so metimes be voided if landowner permission is obtained (e.g., setbacks from property lines), however they are sometimes used to protect the rights of other leaseh olders. Variances from setback re quirements can also be granted by regulatory authorities (typically if operators propose more stri ngent protective drilling and/or operational practices). It should be noted that the efficacy of se tbacks in providing protection for streams may be especially questionable, given th e fact that the network of “blue-line” streams that appears on 71⁄2 minute topographic maps may significantly underestimat e 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 expl anation following in the a ppropriate chapters of the report: special siting criteria (Chapter 1); water resources (Cha pter 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 (C hapter 9); and agriculture and grazing (Chapter 10). In each case, wherever tw o 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 (defin ed 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 histor ical 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 forma tion (located 0 to 9,000 ft below the surface in western Maryland) will obviously require that ope rators drill vertical boreholes through the freshwater zone. Many western Maryland residents are depende nt on groundwater for their drinking water 16 —underlining a critical need to iden tify and understand the hydrogeological setting and dynamics of the princi pal 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 well s (mostly public supply wells) in the Deep Creek watershed in Garrett County w ith a reported combined averag e annual withdrawal of 0.28 MGD in 2007, plus an additional 2,900 permit-exempted i ndividual 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, refl ecting 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 do mestic 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/withdraw als/#ga (webpage accessed December 4, 2012).
17 McPherson, W.S. Water use in the Deep Creek La ke watershed, Garrett County, Maryland, 1980-2007;

http://md.water.usgs.gov/ deepcreek/wateruse/index.html (we bpage accessed December 4, 2012).
18 Ibid.Recommended Best Management Practices for Ma rcellus 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 pr operly cased and cemented to protect fresh groundwater supplies (see Chapter 3). While many neighboring states ha ve mapped the interface between saline and freshwater aquifers, Mary land has not. Water quality data from eight different projects conducted in th e Northern Appalachian Coal Ba sin indicated total dissolved solids (TDS) levels between 2,000 an d 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) fo r underground sources of drinki ng water (Zebrowski et al. 1991). It was reported that one deep well drilled in southern Garrett County encountered a freshwater/saltwater inte rface 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-s ections or quantitative data th at could be used to develop flow nets or models to infer gr oundwater flowpaths and other importa nt 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 focuse d 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 freshwat er/saltwater inte rface would be a useful product from such an analysis. Provi ded with adequate reso urces, the Maryland Geological Survey (MGS) might be the logical group to undertake such an investigation.

The principal aquifers of ungl aciated western Maryland includ e: (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 a quifers in these rocks). In the Appalachian Plateau in western Maryland, the principal aquifers have been identified as belonging to the Monongahela Formation, the Conemaugh Formati on, the Allegheny-Pottsv ille Group, the Mauch Chunk Formation, the Pocono Formation, and the Gree nbrier Formation (the latter is a limestone formation that is only locally water-yie lding). The Monongahela, Conemaugh, and Allegheny Formations each contain multiple seams of mi neable 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 Forma tion, 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 Provi nce it has been suggested that groundwater flow is “step-like”— following vertical pathways through fractures and horizontal pathwa ys through fractured sandstone aquifers and coal beds . Groundwater recharge in the pr ovince 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 pr ovince. Even in areas where groundwater has notK.N. Eshleman & A.J. Elmore (2013) Chapter 1

1-14 been impacted by earlier oil and gas deve lopment that began as early as the 19 th century, saline water can be encountered in aquifers within just a few hundred feet (or le ss in some cases) of the ground surface. Hydrogeologists have attributed this situation to (1) the pr esence of nearly flatlying low permeability strata of shales, siltstones, clays, and dense limestone; and (2) the lack of intensely fractured formations that effectively pr event 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 th rough improperly cased or plugged oil and gas wells that penetrated deeper saline aquifers ; there are other exampl es of fresh groundwater contamination from infiltration and percolation of brines stored in open pits (Trapp, Jr. and Horn 1997).

In the Valley and Ridge Provin ce, it is thought that groundwater moves mostly along fractures and bedding planes, and in solution channels wi thin carbonate rocks; the alternately folded sedimentary rocks, combined with a fluvially-diss ected topography, have crea ted a series of local groundwater flow systems that ex ist 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 a nd 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 channe led back to the surface by folding, faulting, and fracturing of the confined aquifers (Trapp, Jr. and Horn 1997). It appear s that these “warm” springs form on the crests or limbs of anticlin es, particularly where vertical permeability is enhanced at openings along beddi ng planes, tension fractures, ope n faults, or other fractures common to folded structures (Hobba, Jr. et al. 1979). Thus, there definitely are hydrogeological pathways by which groundwater heated at grea t depths (i.e., several thousand feet below the surface) flows upward through fault or fracture syst ems under pressure and discharges at surface springs in the Valley and Ridge Province. White Su lfur Spring and Black Sulfur Spring in Green Ridge State Forest may be less well-know n examples of this same phenomenon.

A major concern with hydraulic fracturing is th at fractures may propaga te vertically upwards into the freshwater zone (or intersect with natu ral fractures), thus increasing the communication between the target gas formation and undergr ound sources of drinking water (USDW), thus providing a mechanism for contamination of drinking water sources. We couldn’t find any conclusive studies documenting contaminati on 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 cons ensus seems to be that there are two distinct mechanisms by which groundwater contamination c ould 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 provid es 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 r ecommend that Maryland follow guidance from New York’s experience in regulating unconventiona l shale gas development and effectively notRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

1-15 permit MSGD (or any other unconventional gas deve lopment) where the target formation occurs within 1,000 vertical feet of USDW or within 2,000 verti cal feet of the ground surface (NYSDEC 2011). While the strati graphy of New York’s Marcellu s 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), th e basic stratigraphy of the Devonian formations is quite similar (Kostelnik and Carter 2009). Since the freshwat er/saltwater interface has not been mapped in Maryland, the prudent approach woul d be to rely on the 2,000 ft crit erion 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 purporte dly indicate that the closest a vertical fracture came to a USDW was 2,800 ft and the typical distance wa s nearly 5,000 ft; data from hundreds of fracturing treatments in the Marcellus shale disp layed in the same report shows a similar result (Fisher 2010). An important limitation of this inte rpretation is that neither analysis included any micro-seismic measurements where the target sh ale formation was within 4,000 ft of the surface. On the other hand, rock mechanics theory suggests that a hydraulic fractur e 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 over burden stress—so hydrauli c fractures would be predicted to propagate primarily in the horizontal dire ction. In deeper rese rvoirs, however, the least principal stress wo uld likely be horizontal and hydraulic fractures would thus be expected to propagate vertically (USEPA 2004). In Ch apter 4 we discuss methods by which vertical propagation of fractures can be estimated.



### G. Stakeholder engagement (e.g., ed ucation, town hall meetings, local community interactions, landow ner 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 con cerns 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 a nd increasing the flow of timely and relevant information to surface owners, users, and other stakeholders. As recommended for Pennsylvania, Maryland might consider developing a standa rdized 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 th e most effective ways possible, while allowing the permit review process to be e xpedited (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 criteri a for siting well pads within a region is based on the idea that some natural (e.g., geologi cal, hydrological, etc.) or man-made (e.g., underground mining) factors may si gnificantly increase specific risk s associated with shale gas development; efforts could be made to identify su ch criteria prior to de veloping the gas resource so that operators and regulatory authorities can make use of su ch information during the permit application and review process. One such restri ction is the topography; we ll pads should be sited on land with a slope of <15%. Mu ch 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 th at most MSGD operators avoid slopes greater than 15%, likel y making this recommendation moot 19

. 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 pathwa ys by which aqueous or gas-ph ase contaminants could rapidly migrate away from a site in the event of a cas ing or cementing failure. Moreover, such voids present technical challenges and safety issues bot h 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 fo llowing cementing operations (Abbas et al. 2003/2004). Voids are very commonly encounter ed when drilling in southwestern Pennsylvania 20 , 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 annul ar 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 surfac e) 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 Depart ment 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 prec autions not necessary in other parts of the state; such additional safeguards may include changing proposed well loca tions 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 predrillin g 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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1-18 At the time of this report, spatial locations fo r 33 caves in Garrett and Allegany counties were available. These locations are aligned along rela tively narrow bands in the vicinity of where limestone units crop out at the su rface (Figure 1-4) w ith two locations falli ng 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 known 23 . 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 Maryland 24 . However, due to horizontal drilling techniques it should be possible to avoid drilling through these highly permeable formations and voids (both mapped and unmappe d)—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 applie d. The technical capabil ity to drill horizontal lateral wells many thousands of feet long unde r such cave systems may allow the shale gas resource to be extracted in a way that signi ficantly 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 Accide nt 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 Potom ac field, the Georges Creek field and the Casselman field) that has left a legacy of underg round voids that present r eal challenges in terms of well isolation. Drilling in the vicinity of act ive 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 dril ling process. Further, casing through these voids would re quire cement “squeezes” from the surface that are subject to failure. Finally, steel casing coul d be subjected to corrosive ac id mine drainage (AMD) that might be present in abandoned underground worki ngs, possibly leading to a catastrophic casing failure over time. For these reasons MSGD shou ld 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 terrain 25

.

23 Ibid.
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the mapped limestone formations; and (2) since caves in th e Greenbrier formation in Garrett County are expected to be confined to a weathered zone within 200 ft of th e 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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stitute

e dK.N. Eshleman & A.J. Elmore (2013) Chapter 1

1-20 coal bed methane wells, and gas seeps and spri ngs within two miles of such wells. COGCC maintains a GIS map system that has a data la yer showing bottomhole lo cations 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. Ma ryland should develop a GIS of both active and abandoned oil and gas wells (including gas storage wells) and ac tive 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 Marce llus 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 de ep 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 throug h implementation of these setbacks, Maryland might also consider mandating the use of surf ace 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. Reclamat ion planning Another very important conclusion from our review of the literature and of activities in other states is that for planning purposes, MSGD in frastructure should be considered a quasi-Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

1-21 permanent (i.e., at least 30 years) industrial ad dition onto a mostly rural Appalachian landscape. We have drawn this conclusion because: a) Marce llus 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 Utic a 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 th e fact that the drilling/hydrauli c 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 n early $11 in July 2008; see Figure 1- 7). The thinking there is that many of the most serious impacts (i.e., erosion an d 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 multip le reclamation efforts over time at the same sites.

The quasi-permanent superposition of this indus trial infrastructure onto the landscape and associated time delays until any permanent site restoration, reclamation, and well plugging takes place has important implications fo r 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 qui ckly 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 perfor med. We feel strongly that the costs of reclamation should be borne directly by the operators (using resource s set aside or accumulated for this specific purpose)—as opposed to ultimately passing these cost s on to Maryland residents in the form of future tax liabilities and diminished natural a nd 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, dr illing and completing a well (or wells), preventing erosion and sedimentation impacts, controlli ng 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 f ound 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 unconve ntional development in gene ral including: (1) anK.N. Eshleman & A.J. Elmore (2013) Chapter 1

1-22 environmental assessment; (2) a cert ificate of liability insurance; (3) a performance bond; (4) a copy of the oil and gas lease; (5) written approval by the local z oning authority that all planning and zoning requirements have been met; (6) an a pproved 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 direct ional 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 wate r withdrawal and storage issues, drilling waste and wastewater treatment and disposal issues , as well as transporta tion 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 Ma rcellus 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 acce ssed 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 County 30 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, althou gh 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 shorel ine seem reasonably restrictive. 32 Local zoning ordinances for both counties should be amended to spell out in which zoning dist ricts MSGD would be permitted as a way of minimizing some of the majo r conflicts and public safety issues that we have identified in this report.

With respect to performance bonding, Maryla nd’s requirements under current regulations ($100,000 per well or $500,000 blanket bond fo r all of an applicant’s wells 33 ) are relatively high compared to other states that we reviewed (e.g., Section 215 of Pennsyl vania’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 lim its are higher for drilling in Pennsylvania state forests). Performance bonding has been deemed inadequa te for providing financial assurance for addressing decommissioning, site reclamation, a nd legacy responsibili ties associated with MSGD (Mitchell and Casman 2011). Mitchell & Ca sman (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 specu late 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 acr eage of mineland in the state were forfeited. Since the costs to reclaim this mineland wa s 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 en tity (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 co mparatively high, another concern is that steep declines in gas producti on of these wells in tandem w ith increasing liabilities for decommissioning and reclamation may drive divest ment of shale gas assets before expected closure occurs. The transfer of marginally-productive assets to sm aller independent operators or even to surface owners is a common practice in the oil and gas industry, with the primary exploration and production compan ies 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 condi tions in which the accumulated reclamation liabilities dwarf the financial wh erewithal 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 them selves would be liable for the reclamation costs down the road. Another problem with surety bondi ng is that underwriting firms will only market such bonds when the amount and terms of the liab ility 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 exis ting 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 civi l action (Mitchell and Casman 2011).

We believe that Maryland’s relatively hi gh 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 estimat ed to be somewhere in the range of $60,000 to $700,000 (mean of around $100,000) pe r well (with some economie s 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 be st 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 m echanisms of covering decommissioning and reclamation costs through a trus t 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 ac count. This problem could be solved fairlyRecommended Best Management Practices for Ma rcellus 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 ta x rate to ensure that the pool ed fund is always adequate to cover the expected cumulative liab ility (Mitchell and Casman 2011).



### K. Key recommendations 1-A Pre-development environmental assessment should be conducted on a site-specific basis and include: (1) identificati on 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 res ources in the vicinity of a proposed site (includes well pad and all anci llary development such as cleared areas around a well pad, roads, bridges, culverts, co mpressor stations, pipelines, etc.); (3) identification of the appropria te 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 leas t two years of site specific data collection prior to any site developmen t 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 expl oitation of the gas re source. Spacing multiwell pads in clusters—as far apart as is technically feasible—m akes maximum use of horizontal drilling technology and could be an important BMP in terms of minimizing development impacts. With careful a nd thoughtful planning (e.g., co-location of infrastructure wherever possibl e), it may be possible to deve lop 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, t hus allowing the regulatory enforcement arm of MDE (with little recent experience in gas well permitti ng and no experience in unconventional gas) to ramp up over time.

1-D Maryland should consider legisl ation that would enable the state to implement “forced pooling” as a way of providing greater resource protection wh ile 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 ecologi cal, recreational, hist orical, 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 importan t 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 standa rdized stakeholder process that could be implemented as part of comprehensive pla nning strategy; the goal of such a processK.N. Eshleman & A.J. Elmore (2013) Chapter 1

1-26 would be to engage stakeholde rs 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 guida nce from New York’s experience with unconventional shale gas development and e ffectively not permit MSGD (or any other unconventional gas development) where the targ et formation occurs within 1,000 vertical feet of USDW or within 2,000 vertical feet of th e 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 ve rtical drilling (i.e., surface boreholes) in areas wher e shallow caves and caverns have been mapped or where there is a high probability that such system s 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 fo rce rapid partial reclamation (including revegetating disturbed areas surrounding wells pads, corridors, and ancillary infrastructure) of all land not needed for drilling and producti on as quickly as possible, while allowing the remaining portion to exist unreclaimed only until such time as drilling is completed, production ends, and fi nal 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 el ements 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 wastewat er treatment and disposal issues, as well as transportation planning issues.

1-M Local zoning ordinances for both counties s hould 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 th at we addressed in this report.

1-N Maryland’s requirements for performan ce 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 d eclines. Nonetheless, Maryland might want to consider alternate mechanisms of covering decommi ssioning 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 alte rnative to performance bonding.Recommended Best Management Practices for Ma rcellus 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. Harris burg, 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 w astewater. 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 Appa lachians. 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 th e stratigraphy of the Oriskany Sandstone: A necessity in assessing its site-specific carbon sequestra tion potential. Environmental Geosciences 16 :187- 200. Lien, A. M., and W. J. Manner. 2010. The Marcellu s shale: resources for stakeholders in the Upper Delaware watershed region. Pinchot Institute for Conservation. Marcellus Shale Advisory Commission. 2011. [Penns ylvania] 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 E nvironmental Impact Statement on the Oil, Gas, and Solution Mining Regulatory Program. Ohio Legislative Service Commission. 2010. Final an alysis: 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 Econom ic & 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 r esources 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. Hydrol ogy of area 6, eastern coal province, Maryland, West Virginia, and Pennsylvania. Water-Resources Inv estigations 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 Recommendati ons 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 Undergr ound Sources of Drinking Water by Hydraulic Fracturing of Coalbed Methane Reservoirs St udy. 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. Bo yer. 1991. Reservoir characterization and production potential of the coal seams in Northern and Central Appalachian basins. Proceedings of the 1991 Coalbed Methane Symposium. Univ ersity of Alabama Tuscaloosa.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

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### 2. Protecting air quality 1
Natural gas from MSGD has the potential to pr ovide 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 (predo minantly methane) has advantages over coal with respect to trapping of in frared radiation (IR) by greenhouse gases (GHGs) and contributing to planetary warming. The GHG advantage of natural gas arises from the rela tive heat (available for energy production) per unit of CO 2 released in combustion. For each molecule of CO 2 produced, roughly twice as much energy is availa ble from natural gas than from coal. This advantage is only realized if the gas is combus ted 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 coal 2 . Actual emission rate s 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. Noneth eless, there is some evidence that emissions rates may be significantly higher than in itial 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 combusti on of a molecule of carbon or methane produces one molecule of CO 2 , but the methane produces roughly twic e as much heat represented by the enthalpy of combustion, DH°.

C + O 2 → CO 2 DH° = -94 kcal/mole CH 4 + 2O 2 → CO 2 + 2H 2 O DH° = -193 kcal/mole

The ratio depends on details such as the ex act composition of coal and gas but can be approximated as 193/94 = 2.05 or ~ 2. Substantia l 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: na tural gas is better for climate than coal as long as losses can be kept below 3% of total production.

Maryland’s primary air quality i ssues from among all of USEPA’s criteria pollutants are ozone (O 3 , also called photochemical smog or Los Ange les type smog) and fi ne particulate matter (PM 2.5 , the mass of particles less than 2.5 μ m in diameter in a cubic meter of air). Maryland is in violation of the National Ambient Air Quality St andard (NAAQS: 75 parts per billion for an 8-hr average) for ozone and in or near compliance for PM 2.5 , 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. (Appal achian Laboratory, University of Maryland Center for

Environmental Science, Frostburg, MD 21532); Russell R. Dickerson, Ph.D. (Depar tment of Atmospheric and Oceanic Science, University of Ma ryland, 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. Elm ore (2013) Chapter 2

2-2 visibility or visual range. The lim it to visual range is generally fine particles, so comments on PM 2.5 also apply to haze. Maryland is a member of the Regional Greenhouse Gas Initiative (RGGI) that seeks to limit emissi ons of pollutants that disrupt the Earth’s radiative balance including carbon dioxide, nitrous oxide, and meth ane. On a local scale, hazardous air pollutants (HAPs), malodorous gases such as hydrogen sulfide (H 2 S), and mercaptans (organic sulfur compounds) can be of concern, and radon (an α particle-emitting, respirab le radioactive material produced as a decay product of radium present in the Marcellus shale formation) 3

. In terms of emissions, Maryland’s to p priorities are the precursors to O 3 and PM 2.5 (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 reacti ons involving two main classes of precursor pollutants: volatile organic compoun ds (VOCs) and nitrous oxides (NO X ); carbon monoxide (CO) is also important for O 3 formation in polluted areas a nd in the remote troposphere. The formation of O 3 from these precursors is a comple x, nonlinear function of many factors including: (1) the intensity and spectral distri bution of sunlight; (2) atmospheric mixing; (3) concentrations of precursors in the ambient air and the rates of chemi cal reactions of these precursors; and (4) processing on cloud and aerosol particles (USEPA 2012). Fine particular matter (PM 2.5 ) are those particles (such as those found in smoke and haze) that can be deeply respired into the lungs; wh ile the sources of these particles can be from fo rest 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 automobile s react in the atmosphere. The most common gases cited as precursors of PM 2.5 formation include: sulfur dioxide (SO 2 ), NO x , VOCs, and ammonia (NH 3 ). Secondary formation of O 3 and PM 2.5 is thus linked by virtue of involving some of the same precursor pollutants.

High quality (dry) natura l gas is composed primarily of methane (CH 4 ), but contains appreciable amounts (percentages) of other lig ht alkanes such as ethane (C 2 H 6 ), propane (C 3 H 8 ), butane (C 4 H 10 ) and pentane (C 5 H 12 ). The amounts decrease with incr easing carbon number, but recent evidence indicates wide variab ility among MSGD wells in neighboring states. Methane and the light alkanes themselves do not c ontribute significantly to ground level ozone or fine particulate matter. Heavier and unsaturated volatile orga nic compounds (VOCs), particularly biogenic isoprene, do contribute substantially to ozone formation, however. H azardous air pollutants (HAPs) may also arise from natural gas produc tion. Recently, evidence indicates that some natural gas operations could be non- negligible sources of benzene (C 6 H 6 ), a variety of other HAPs, and heavier hydrocarbons (McKenzie et al. 2012, Petron et al. 2012, personal communication: R. Schnell, Gl obal Monitoring Division, NOAA). Th ese could pose a health risk to individuals living within ~1000 m of a gas operation.

3 Among different types of rocks, granites and rhyolites (ign eous 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 Ma rcellus Shale Gas Development in Maryland

2-3 The purpose of this chapter is to examine the sources of pollutants a nd air pollution precursors associated with MSGD operations and make r ecommendations of best management practices that should be use to contro l such emissions and protect ai r quality in Maryland locally, regionally, and globally. Ozone and PM 2.5 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 sc ales of 1-5 d. Releases of primary pollutants (particularly NO x ) in western Maryland where MSGD could occur could certainly have adverse effects on eastern Maryland where NAAQS ozone viol ations occur. The regional scale of these problems would suggest that even if MSGD doe s 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 NO x into a regional atmosphere upwind (i.e., west) of Maryland w ould be expected to make it more difficult for the state to meet the NAAQS for ozone in the future. While no stud ies have been published on regional air quality impacts from MSGD, one numerical atmospheric modeling study of Texas and Louisiana indicated increases in th e 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 precur sor emissions from MSGD operations Implementation of BMPs to control air polluti on 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 Ne w 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 ai r pollution precursors) described above.

Methane and VOCs. Determining BMPs for reducing methane and VOC emissions from MSGD is in part dependent on identifying and inventoryi ng 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 (Armendari z 2009) provides useful information that may be relevant to western Maryland. Emi ssion sources in the gas industry can be classified as follows: (1) fugitive emissions; (2) vented emissions; an d (3) combustion emissions. Fugitive emissions are unintentional leaks around seals and gaskets, leaks from underground pi pelines due to from corrosion or faulty connections, or emissions th at occur during the well completion process. Vented emissions are releases to the atmosphere by design or opera tional practice. Examples of vented emissions include: emissions from conti nuous process vents, such as dehydrator reboiler vents; maintenance practices, such as blowdow ns; and small individual sources, such as gas operated pneumatic device vents. Combustion emi ssions 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 abso lute 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 comp letion (Howarth et al . 2010); (2) fugitive emissions from compressor station and transmi ssion systems (Kirchgessner et al. 1997, Howarth et al. 2010); and (3) routine ve nting emissions (Kirchgessner et al. 1997, Howarth et al. 2010).K.N. Eshleman & A.J. Elm ore (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, performe d 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 transpor ted into production pipe lines 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 ta nks, and piping that had been installed at the well site; condensate tanks are sources of emissions th rough venting to the atmosphere. “Green completions” are considered highly cost-effectiv e 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 NES HAP for oil and natural gas production.

Unfortunately, a major loophole in implementing gr een 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 ga s development plan, Maryland could work with industry to site early pads at specific locations where “wildcat ting” 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 comp ressor 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 meth ane emissions were recently instituted by USEPA: (1) use of modified (“low bleed”) pneuma tic 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 (9 8%) devices that can dramatically reduce VOC and methane emissions from tanks (Armendariz 2009). USEPA is also trying to address VOC emissions for natural gas pro cessing plants through the NSPS process—in particular controlling fugitive emissions from se parators, 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 pe rformed using handheld organic vapor meters (OVMs); inspections are performe d at a specified frequency under the NSPS. Natural gas that is low in high molecular weig ht hydrocarbons may not re quire such processing, and we are not sure whether such pl ants will be required in Maryland.

Expansion of a comparable leak detection a nd repair program that governs operations from wellhead to the transmission line would be c onsidered a BMP for reducing emissions in Maryland and elsewhere, regardless of whether processing plants are necessary. Thermal imaging cameras (e.g., FLIR Commercial System s B.V., Breda, The Netherlands) have been used to great effect in identifying hydrocarbon leak s in Houston refineries. These cameras can be mounted on aircraft to survey br oad areas to identify major leak s 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 QualityRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

2-5 (TCEQ) has identified leaks that, when repaire d, 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 industry 5 ; as proposed for New York State, best practice in Maryland would be that all operators vo luntarily participate in this program and implement as many of the recomm ended 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 sy stems; (3) reducing emissions when taking compressors off-line; (4) replacing gl ycol dehydrators with desiccant dehydrators; (5) replacing gas-assisted glycol pumps with el ectric pumps; (6) optimizing glycol circulation and installing flash tank separators in glycol dehydrator s; (7) using efficient compressor engines; (8) using efficient line heaters; (9) using efficient glycol dehydrators; (10) re-using production brines; (11) ensuring all flow c onnections are tight and sealed; (12) performing leak detection surveys and taking corrective actions ; (13) using efficient exteriorlighting; and 14) using solarpowered telemetry devices.

NO x . Unlike VOCs and methane that are principally emitted through fugitive and venting mechanisms, NO x is primarily a product of operating in ternal 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 dr ill rigs can be powered off of the electrical grid where NO x is effectively capped at the electrical generating plant unde r the Clean Air Act Amendments. Smaller combustion engines are us ed to power compressors that produce and transport the gas through pipeline s; these engines can be powered by either diesel fuel, natural gas, or electricity. An obvious best practice for controlling NO x emissions from MSGD in Maryland would be through the us e 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 po wer is available (or could be made readily available); this alternative might be reasona bly 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 app licable 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 NO x emissions based on USEPA 1998 standards for heavy-duty diesel highway vehicles of 4.0 g NO x /bhp-hr 6 equivalent to 25 g NO x /kg fuel 7 . In Texas, TCEQ has taken a similar approach in regulating NO x emissions in the Dallas-Fort Worth metropolitan area, although TCEQ used an even more stringent emissions standard of 0.5 g NO x /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 opti ons would have significan t 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 ve hicles, but not as stringent as the 2007+ standard of 0.2 g

NO x /bhp-hr.K.N. Eshleman & A.J. Elm ore (2013) Chapter 2

2-6 of reducing VOCs as well, but e ngines (i.e., drilling devices, co mpressors, trucking etc.) could also be required to meet the “fleet averag e” of all engines set by the USEPA 1998 hydrocarbon (HC) standards for heavy-duty diesel highway vehicles of 1.3 g HC/bhp-hr 8

.

PM 2.5 . We recommend that Maryland require the “fleet average” of all internal combustion engines (i.e., drilling devices, compressors, pum ps, trucking etc.) used in MSGD meet USEPA 1998 standards for heavy-duty diesel highway vehicles of 0.1 g PM/bhp-hr 9 . Restricting idling time and requiring use of ultra low sulfur diesel (ULSD) fuel w ould 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, toluen e, 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 radio active material (NORM), principally radium-226 ( 226 Ra)—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 unlikel y 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) asso ciated with developing the Marcel lus shale would be to develop and implement an air emissions monitoring prog ram 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 Mary land establish a methane leak detection and repair program that governs operations from wellhead to th e transmission line, re gardless of whether processing plants are necessary. All operato rs 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-d uty/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 Ma rcellus Shale Gas Development in Maryland

2-7 2-B Encourage operators to either use newer in ternal combustion engi nes or convert from diesel internal combustion engines to electr ic motors for operating drilling rigs, pumps, and compressors wherever possible by impl ementing “fleet average” emission standards for NO x , VOCs, and PM 2.5
. 2-C Require monitoring of hazardous ai r 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 pr oduction 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. Ha rrison, 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 unconventiona l natural gas resources. Science of the Total Environment, 424 :79-87. NYSDEC. 2011. Revised Draft Supplemental Generic E nvironmental 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 A ssessment for Ozone and Related Photochemical Oxidants (Third External Review Draft). EPA/600/R-10/076C. Resear ch Triangle Park, NC: U.S. Environmental Protection Agency, Office of Research and DevelopmentRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-1 

### 3. Well engineering and construction practices to ensure integrity and isolation 1
The primary goal of the oil and natural gas industr y is to cost-effectively explore for and extract petroleum and natural gas from subsurface enviro nments 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, sa fe, and controlled way. Obviously, well engineering and construction practices have evolved over time as operators have gained greater experience and as technological improveme nts have allowed. For a century or more in an era in which environmental resources were not grea tly considered, the indust ry 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 sta ndards. 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 a nd rivers or seeped in to groundwater causing widespread water pollution.

In recent decades, the industry has responded to pressure to re duce 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 fr om the surrounding subsurface environment, and effectively contain the produced gas and other fluids within the well’s innermost production conduit so it can be successfu lly transported through ancillary pipelines for processing and delivery to market. Heightened environmental aw areness and elevated environmental standards have also forced the industry to make substa ntial progress in collec ting, storing, treating, and recycling of liquid drilling wastes (i.e., “flowback”, brines), although the indus try still relies very heavily on underground injection as the ultimate di sposal 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 opera ting oil and natural gas wells; on the basis of its on-going technical reviews of various pr actices, API has published an ex tensive number of documents describing so-called “recommende d practices” (RPs) which it communicates and shares with the industry. Many of these RP’s e xplicitly address problems in maintaining well integrity and provide standards that have been expressly adopted by some state regulatory authorities.

Obviously, not all well construc tion 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 ga s wells into aquifers over the lifetime of a producing well (Myers 2012); the au thor of a white paper on the s ubject described the science of understanding this problem as “recent, ongoing, and incomplete” (Ingraffea 2012). The recent

1 Chapter author: Keith N. Eshlem an, 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 transp ort through porous media overlying a hydraulically-fractured shale formation and pr eferential transport through fractures, but significant questions have been raised regardi ng 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 relations hip to hydraulic fract uring remains unproven (Osborn et al. 2011, Davies 2011).

The Deepwater Horizon oil spi ll in the Gulf of Mexico in 2010 following the Macondo well blow-out is a chilling reminde r 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 inves tigation into the causes of this accident also highlighted a series of decisions that complicat ed the cementing operation, increased the risks of failure, and were major contributing factors in the blow-out and explos ion on April 20, 2010 that killed 11 men working on the drilling platform a nd caused the subsequent spill of an estimated 4.9 million barrels of oil into the Gulf of Me xico (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 workin g 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 ma nagement 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 St ate). Other best practices that are considered ancillary to well drilling, completion, and pr oduction (e.g., BMPs for containing, treating, and disposing of drilling wastes—especially “flowbac k” and brines) are discussed in Chapter 4.



### A. Well planning

API provides a very detailed explan ation of the critical need for operators to perform adequate well planning as a first step to ensu ring well integrity a nd isolation (API 2010) 2 . The rationale for such planning is very well established fr om experience, and optimum well planning for constructing wells for developing the Marcellu s 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 co mmunications 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 recommenda tions may be applicable to other offshore and onshore areas (see p. iii).Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-3 • construction designs and plans for a specific we ll that would include: (1) an analysis of pore pressures, fracture gradie nts, and required drilling flui d 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 a nd 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 planni ng, and we discuss some of the primary constraints on siting a well pad and wells in Chapter 1 (oth er environmental criter ia are discussed in Chapters 5 through 10 of the report). We are partic ularly 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 potent ial 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 recommen d 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 w ith jurisdiction for a particular well will need to review the well plan before operations can begin. All f our 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 plan s recommended by API for offshore operations; in some cases, additional components are requir ed. Pennsylvania’s and West Virginia’s requirements with respect to well planning ar e nearly identical, requiring information on 3

• 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 regul ations, however. Agency review of a well permit application in Ohio includes a review of wells and other potential pathwa ys for contamination of groundwater within the minimu m spacing distance for a propos ed well (with the review extending along the entire latera l of a horizontal well and incl udes 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 al so 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 pl anning, plans for addressi ng lost circulation, and hydraulics plans for controlling all static a nd dynamic borehole pressures. API (2009a) also recommends that operators inve stigate and review the history of nearby wells for cementing problems encountered (e.g., lost returns, irregul ar hole erosion, poor hole cleaning, poor cement displacement, etc.) prio r 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 ons hore development. API may choose to eventually develop BMPs for well planning that are specific to onshore operat ions, but until such practices can be determined, the adoption of the practic es advocated in API St andard 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 effectiv ely communicated these, and contingencies for addressing them, to all subcontractors and to the appropriate re gulatory authorities prior to spudding the well. Ohio’s requirement for pre-pe rmit 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 ga s well typically requires several cy cles of drilling, installing of casing strings, and cementing casing strings in pl ace to ensure integrity and isolation. During each cycle, lengths of steel casing are installe d in sequentially smaller diameters inside a previously installed and cemented casing string. Dr illing 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 ho le, 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 fl uid is normally circulated down the drill string and up the space between the drill string and the hole that: (1) pr ovides lubrication of the drill bit; (2) removes the formation cutt ings; (3) maintains control of pressures in the well; and (4) stabilizes the hole being drilled. Drilling fluid is generally a mixt ure of water, clays, fluid loss control additives, density cont rol additives, and viscosifiers. Drilling fluid is a carefully monitored and controlled mixtur e 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 wester n Maryland any conductor hole would need to be drilled. A conductor hole would logi cally be drilled to a depth that would provide isolation from any nearby water wells or freshwater spri ngs. The conductor hole would be followed by sequentially deeper (smaller diamet er) holes drilled to install the surface casing, the intermediate casing (if necessary), and the production casing (API 2009a).Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-5 Prior to drilling, best practice would be to eith er slightly crown the location around the wellbore to divert fluids to a flow ditch, or construct a li quid-tight cellar at least th ree ft in diameter to prevent surface infiltration of fluids adjacent to the wellbore. A Marcel lus 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 USDW 5 ); in many areas, coal seams will also be encountered while drilling fo r the surface casing. Caution must be taken while drilling through this zone to adequately protect USDW from contaminati on, and state regulations are meant to require operators to prudently drill through fresh groundwat er zones so as to minimize disturbances to such zones 6 . One way that this can be accomplished is by drilling all intervals prior to reaching a “U SDW protective depth” either on compressed air, fresh water, a freshwater-based drilling fluid, or a combination of the above. Oh io, for example, requires that only additives that are suitable for drilling thro ugh 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 requi re 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 (A PI 2009a). The intermediate hole would not likely be drilled “on air”. Downhole motors (which operate using the hydra ulic pressure exerted by the drilling fluid) are “steerable ,” meaning that the di rection (in all dimens ions) of drilling can be controlled from the surface to stay within th e target formation (API 2009a). New York State has recommended that both the intermediate a nd 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 su rface. These flexible dr illing 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-base d. Synthetic oil-based muds are described as “food-grade” or “environmentally friendly.” When drilling horizontally, m ud is needed to: (a) power and cool the downhole motor and bit used for directional drill ing; (b) operate the navigational tools which require mud to transmit sensor readings; (c) pr ovide stability to the horizontal borehole; and (d) efficiently remove cu ttings 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 well bore (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 fl uid 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 fragment s. Air drilling also reduces wastewater generation and subs equent treatment (Lien and Ma nner 2010), but it cannot always be done safely—especially under conditions in wh ich 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 pressure s; well pressures can be held in check as long as the mud weight is sufficient to prevent flow s 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, suffi cient liquid shall be available on-site to kill any unexpected flow from a particular well 9 . 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 drilling 10 ), 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 ope rators to determine when the USDW protective depth has been reached while drilling the surface hole (l ikely on the basis of data obtained from geophysical l ogs 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 regulatio ns require that a string of surface casi ng 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 regulati ons. 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 su rface, 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 Ma rcellus 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 approved 12 . Ohio also requires that a ny wellbore diameter shall be consistent with manufacturer's recommendations fo r all float equipment, centralizers, packers, cement baskets, and any other equipment that will need to be run into the wellbore 13

.



### C. Casing and cementing Casing and cementing are critical elements of any well construc tion that must be properly designed and engineered to ultimately serve th eir primary purpose of providing well integrity and isolation from surrounding subsurface forma tions 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 le ngthy 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 s upport of the well, and protect the casing from corrosion. The cement must also be able to cont ain all pressurized fluids during all phases of drilling and operation of the well. Operators (i ncluding company engineers who design the well casings, their supervisors, and any drilling subcontractors invo lved in casing installation and cementing) bear the primary responsibility for ensu ring 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 (“cr oss-sections”) of the subsurface strata in western Maryland (including depths that various formations will like ly 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 likel y that Marcellus shale ga s wells in Maryland will normally require four casing strings (i.e., condu ctor 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 a ll anticipated hydraulic fracturing pr essures, production pressures, and corrosive conditions expected to be encountered. Used or reconditioned casing would only be used if it is shown to meet API standard s 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 cas ing strings should be a ssembled to the correct torque specifications to ensure leak-proof c onnections. Casing centralizers should be used to properly center the casing in the hole and pr ovide 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 determin ing the type, number, and best placement of centralizers along a particular cas ing string (API 2009a). Maryland should require that operators use casing that meets the high standards recomme nded by API, as well as a sufficient number of centralizers to properly center the casing in each borehole.

API also provides good recommendations of materi als and practices for en suring that the various casing strings are properly cemented in place a nd 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 appr opriate 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 completi on of the well. Cementing is best achieved by pumping a cement mixture (or “slurry”) down inside the casing stri ng 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 drilli ng fluids inside the casing while the cement is being pumped. Zonal isolation and integrity of th e 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 filli ng 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). Appr opriate testing of cement shoul d always be carried out by the service company to ensure that the mixture meets the criteria specifi ed 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 prepar ation to the manufactur er’s or contractor’s specifications to minimize free water in the ce ment; 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 st atic until all cement has reached a compressive strength of at least 500 psi before dr illing the plug, or initiating any integrity testing 14

. 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 la rge underground voids are encountered during drilling that preclude circulati on 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., 4Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-9 “top job”) on a conductor casing, but this appr oach is normally not recommended because of difficulties in isolating the various water-bear ing formations and thus protecting USDW as discussed in Chapter 1. In one of its publicati ons, API notes that “a t op job should be done only as a last resort” (API 2010). If it is determin ed that a “top job” will be necessary, then the conductor casing should be installe d as deeply as possible to pr otect 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 interm ediate casing should also be done in the normal manner (i.e., bottom to the surface), but notes that th ere 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 circ ulation of the slurry). According to King (2012), in cases of very long intermediate casing st rings, cementing the full casing string may be illadvised due to the risks of fract uring formations by the pressure exerted from the weight of a column of cement (nearly twice th e weight of an equivalent column of water). On the other hand, cementing an intermediate string to an insuffici ent height may leave th e annulus exposed to higher pressures from non-isolated gas-containing shales and coal s 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 overpre ssurization and flow through the annulus, there is one older study that addresse d this problem using a modeli ng approach (Harrison 1985). A more recent paper hypothesizes that high methane c oncentrations in drinking water aquifers in Pennsylvania are most likely attributed to a nnular overpressurization resulting from leaky well casings rather than from hydraulic fracturing (O sborn et al. 2011), although other mechanisms are at least as plausible (Davies 2011, Jackson et al. 2011). Data from Wa rner 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 geologic al conditions that are encountered while drilling in western Maryla nd. At a minimum, however, an absolute requirement should be that all flow zones (inc luding USDW) must be fully protected through the use of cemented intermediate well casings. Wher e this cannot likely be accomplished with a single casing string, the use of multi ple 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 ca sings have significant implications for upward contaminant migration into USDW; a recent whit e paper provides a description of several mechanisms by which oil and gas wells develop fl uid leaks and lose thei r structural integrity (Ingraffea, 2012): (1) repeated pr essurization of casings with ope n-annulus sections; or (2) high gas pressures encountering curing cement or ente ring open-annulus sectio ns. 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 cove r 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 form ed in settingK.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-10 cement can allow for gas or fluid migration thro ugh the annulus if these voids are continuous. Fortunately, large voids or channe ls 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 addresse d accordingly (King 2012).



### D. Well logging Useful geophysical data to support MSGD in Mary land would likely be obt ained from a variety of sources, particularly: (1) published geologica l maps of the region from USGS or private sources; (2) available well log records from previ ous gas and water well drilling in Maryland and surrounding states; (3) results from seismic refract ion tests conducted as part of exploration activities; and (4) results from test (“pilot hole ”) drilling (the latter pr oviding information for improving stratigraphic interpretatio n specifically through calibration of seismic data). Data from these sources would likely be sufficient to: (1) id entify subsurface drilling hazards; (2) accurately assess the location of the target zone; and (3) en able the design of production wells and detailed well plans. Once drilling for produc tion actually begins, there are many types of data that would be collected through well logging techniques to pr ovide detailed records of subsurface properties actually encountered in the well construction process.

Open-hole logging is a method used in borehole geophysics that is conduct ed after drilling the hole, but before any casing is installed. Open- hole logging can provide im portant information on the specific depths of various formations enc ountered during the drilling process—and is thus very important in optimizing the well design and drilling operations. Dr illing each hole to the correct depth theoretically allows casing strings to be installed at optimal locations to achieve maximum well integrity (API 2009a). Logging wh ile drilling (LWD) technology was initially developed in the 1970s, but the t echnology 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 wire line technology, it is possible to accurately determine formation properties from gamma ray logs (l ithology), electrical resistivity logs ( hydrocarbons), neutron porosity logs (liquid-filled por osity), and density logs (bul k 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 ceme nt 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 additi onal 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 cementin g 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, th e casing collars, and the integrit y 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 re cording the amplitude of the arrival signal at a detector. Casing that is not encased in cemen t 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 theRecommended Best Management Practices for Ma rcellus 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 th e 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 zona l isolation. Such channels, if extensive or continuous, could provide a pathwa y 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 loggi ng during a single descent. 15 Additional information on the various types of cement evaluation tools that are av ailable can be found in API TR 10TR1.

We found relatively little agreement among the st ates as to which well logging techniques constitute best practice. Appa rently neither Pennsylvania nor Ohio require any well logging (either open-hole or cased-hole) , while West Virginia require s only a CBL. Colorado requires that operators run a minimum of a: (1) resi stivity log with gamma-ra y or other approved petrophysical logs that adequately describe the stratigraphy of th e wellbore; and (2) a CBL on all production casing or, if a producti on liner is used, on the intermediate casing. Colorado also requires that open hole logs shall be run at depths that adequate ly 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. Ne w York State has proposed that a radial cement bond evaluation log or other approve d method should be use to verify the cement bond on the intermediate casing and the producti on casing (NYSDEC 2011) . The best practice would utilize modern open-hole well logging met hods to help fine tune casing placement and characterize flow and hydrocarbon zones, perh aps mud logging to determine levels of hydrocarbons in real-time during drilling, a nd 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 th e event that problems with cement bond integrity are identified through the logging pr ocess. If remedial actions cannot fully resolve cement bond integrity issues, the operator should have no reco urse but to correctly plug and abandon the well in accordance with state regulations.

Maryland’s current regulations 16 apparently require only elect rical induction and gamma ray “open-hole” logging to determine the depth of fr eshwater, but they also require operators to maintain a detailed driller’s log book 17 and provide MDE with a completion report within 30 days after drilling, stimulating, and well testing have been completed 18 . Such completion reports include, among other items, information on the lit hology of the penetrated strata, generalized core descriptions, estimates of porosity and permeab ility of formations, and copies of all logs run of the well. Maryland should cons ider amending its regulations to require SRCBL (or equivalent casing integrity testing) and ot her types of logging (e.g., neutr on logging) to assist with determining the depth of freshwater as part of a cased-hole program.

15 e.g., Tetra Technologies (2012); h ttp://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.VK.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-12 

### E. Pressure testing API (API 2009a) and the five states that we revi ewed all call for testi ng of the various casing strings after the cement has achieved the appropri ate compressive strength during a pre-specified wait-on-cement (WOC) period, but prio r to drilling out. These tests are known as casing pressure tests and are performed to ensure that the integr ity of each casing string is adequate to meet the well design and construction obj ectives. 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 exampl e, the regulations only state that an operator should conduct the test at a pressure more than 20% greater than the pres sure 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 th e 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 te sts” or “leak-off tests” ) be performed after drilling out both the surface and intermediate cas ings (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 th e conduct of such tests likely established through consultation with industry. Maryland’s current regulations 19 with regard to pressure testing of cemented casings are even less specific than those establis hed by neighboring states and appear to be in need of revision.



### F. Blow-out prevention Blow-out prevention equipment (B OPE) on a rotary drilling rig is a pressure control system installed at the top of the surf ace casing that is designed specifi cally to contain and control a “kick” (i.e., an unexpected pressure resulting in the flow of formation fl uids into the wellbore during drilling operations). BOPE c onsists of four parts: 1) a bl ow-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 BO PE should have at least two redundant (and operational) mechanis ms 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 hol e 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 eff ective, BOPE systems must be maintained and in proper working order during operations; a BOPE te sting program must be employed on a regular basis to ensure that the system is functioning pr operly if and when it is needed (NYSDEC 2011). All BOPE should have a working pressure ra ting that exceeds the maximum expected surface pressure; training exercises or dril ls should be held as necessary to ensure crew familiarity and that the BOPE is in good worki ng order (API 2009a).

BOPE is an example of a temporary mechani cal 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. Colu mns of fluids (e.g., dr illing fluids, cement

19 COMAR 26.19.01.10.S(3)Recommended Best Management Practices for Ma rcellus 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 pressure s 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 mech anical barriers that are used by the oil and gas industry, but we lack the technical capacity to make recommen dations as to which specific types of barriers would be employed in developing Maryla nd’s Marcellus shale gas resource.

Pennsylvania requires the use of BOPE for dr illing production wells for natural gas in unconventional formations 20 , but Ohio and West Virginia do no t. 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, pressu re testing of the cas ing string and each component of the blowout preven tion equipment (if blowout prev ention equipment is required) should be conducted prior to dr illing out any string of casi ng 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 consid ered 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 z onal isolation between the prod uction 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 transporti ng 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 abse nce 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 cemen ting the production string of a well that will be stimulated by hydraulic fracturing, and the uppermost perforati on 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. Recommenda tions 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 annu lar 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 path way 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 fr acturing (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 comple ting 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; redu ce interfacial tension; inhibit scale; etc.) is pumped into the pr oduction casing of a co mpleted 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, frac tures grow throughout the target formation; as the fractures grow, a proppant (san d) is added to the flui d. Once pumping stops and excess pressure is removed, the fractures attemp t 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 migratio n out of the formation (API 2009a).

Technical concerns about hydraulic fracturing have tended to fo cus 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 coul d be transported long dist ances (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 add itives used in making up the HF fluid (and their toxicity). While well beyond the scope of our study of best practices to fu lly explore, we believe that there has been insufficient sc ientific 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 c ontaminants—both gases and liquids—either introduced or native to overpressurized formatio ns such as the Marce llus could impact USDW. Certainly this complexity warrants continued study, both of new methods in well engineering and well completion as they become available, bu t also environmental data demonstrating well isolation has been successful in protecting th e USDW. With respect to the second issue of induced seismic activity, we c ite the recently published National Research Council (NRC) report which concluded that: (1) the pr ocess of hydraulic fracturing a we ll 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 te chnologies 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 num ber of disposal wells in oper ation (NRC 2012 ). Best practices for selecting, handling, and disposing of HF chemicals are discussed in Chapter 4.



### H. Use of well develo pment 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 pr oduce less waste), but at present these techniques appear to be limited to demonstration or pilo t 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 Ma rcellus Shale Gas Development in Maryland

3-15 • Liquid CO 2 . The use of a liquid CO 2 and proppant mixture obviously reduces the use of other additives. Once CO 2 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 ga s is unable to carry appreciable amounts of proppant and the nitrogen foam was f ound to introduce liquid co mponents that can cause formation damage.

• Liquified petroleum gas (LPG). More recently, New York looked into the use of LPG (primarily propane) which has the advantag es 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, mixi ng LPG with natural gas apparently does not “contaminate” natural gas and the mixture may, th erefore, be flowed directly into a gas pipeline and separated at the gas plant a nd recycled. LPG’s high volatility, low weight, and high recovery potential make it a particul arly good fracturing agent. Use of LPG as a hydraulic fracturing fluid also inhibits formation damage which can occur during hydraulic fracturing with conventional fl uids. 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 dis pose of the flowback fluids. As a result of the elimination of hydraulic fracturing source wa ter, truck traffic to and from the well site could be greatly reduced. Fina lly, 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 flow back fluid (NYSDEC 2011).



### I. Determining the exte nt of induced fractures There are two methods that can be used for dete rmining the extent of i nduced vertical fracture growth by hydraulic fracturing. The first techni que 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. Hi storically, tiltmeters have been used extensively for monitoring volcanoes, the responses of dams to filling, a nd 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 appa rently 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 mi cro-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 vertic al fracture growth in hydraulically-fractured Barnett Shale wells typically extends hundreds to thousands of ft above and below the frac depth, but in noK.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-seismi c 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 di scussed in Chapter 1, th ese 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 til tmeter 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 protoc ols 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 re sults for successful gas recovery. It is in the operator‘s best interest to closel y control the hydraulic fracturing pr ocess 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 woul d 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 th e treatment well during the HVHF process. At least one receiver should be in the treatment zone, with another located above and one be low this zone. Maximum observation distances for microsei sms should be within approxim ately 2,500 ft of the treatment well, with the distance dependent on forma tion properties and ba ckground noise levels. Locations are triangulated using th e 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 with in the envelope of ma pped microseisms (NYSDEC 2011). We highly recommend that a sufficient numb er (at least tens) of tiltmeter or seismic surveys be performed as part of MSGD in Mary land, so that the extent , geometry, and location of Marcellus fracturing can be adequately char acterized. The goal would be to feed useful information back to the operato rs, so that subsequent hydrauli c fracturing could be conducted more safely and effectively. Data from such surv eys 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 locate d 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 poten tial production zones. Generally, contamination by an improperly plugged or ab andoned 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 en ter the abandoned wellbor e 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 pr event an abandoned well from becoming a conduit for contamination, well construction and completi on methods also contribute to the prevention ofRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-17 contamination (API 2009b). Plugging should be considered a critical element of the well decommissioning process that al so includes land reclamation.

Well plugging operations are focused primar ily 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 wa ter runoff from seeping into the wellbore and migrating into USDW cement plugs isolating hyd rocarbon and injection/disposal intervals and a plug at the base of the lowermost USDW accomp lishes 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, therefor e, recommended that operators set a cement plug at the base of the lowermost fres hwater aquifer or US DW 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 confin ing those fluids in the well.) In addition to the cement plugs described herein, many state an d federal regulatory agencies require cement plugs across the base of the surface casing a nd in, or between, each producing and potential producing zone (API 2009b).

All formations bearing usable quali ty water, oil, gas, or geothe rmal resources (e.g., coal seams) should be protected and/or isolate d. 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 forma tions 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 un cemented 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).

Pennsylvania 21 and Colorado 22 have enacted regulations govern ing 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 regulations 23 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 de commissioning, the biggest problem that we anticipate with plugging of Marcellus wells in Maryland will be ensuring that the appropriate party is held accountable and ha s sufficient assets to do so. Th e costs associated with plugging wells that were poorly constructed in the fi rst place can be extremel y 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—sur face or coal protective casing is cemented); 25 Pa. Code

§ 78.93 (relating to wells in coal areas—surface or coal protective cas ing anchored with a pa cker 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 noncoa l areas—surface casing is cemented); and 25 Pa. Code § 78.407 (relating to plugging gas storage wells).
22 COGCC Rule 319, Abandonment.
23 COMAR 26.19.01.12K.N. Eshleman & A.J. Elmore (2013) Chapter 3

3-18 

### K. Key recommendations 3-A A best practice for anyone propos ing 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 Chapte r 1, we are particularly concerned about drilling in areas where there is a high pr obability of encountering large underground voids (e.g., caverns, caves, mine workings, ab andoned wells, etc.) that have the potential to cause a loss of fluid circ ulation during drilling and impos e additional risks during the cementing process. Such hazards are local ly 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 situ ations (e.g., very deep wells) where fully cementing the intermediate casing to the su rface 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 cemen ted intermediate well casings. Where this cannot be accomplished feasibly with a singl e casing string, the use of multiple casing strings should be favored in the well design.

3-D Maryland should consider ame nding its regulations to requ ire SRCBL (or equivalent casing integrity testing) and other types of logging (i.e., ne utron 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 technica l details governing the conduct of such tests likely established through consultation with i ndustry. Maryland’s curr ent regulations with regard to pressure testing of cemented casings are even less specific than those established by neighboring st ates 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 fract uring 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 with in 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 th e long expected time lags (of the order of 30 years) between drilling and well deco mmissioning, 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 accoun table for perform ing this critical task. The costs associated with plugging wells that were poorly constructed in the first place can beRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

3-19 extremely high, which reinforces the need to en sure that any Marcellus shale gas wells in Maryland are constructed to the highest standards.



### L. Literature cited API. 2009a. Hydraulic Fracturing Operations--Well C onstruction 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 fractur ing. American Oil and Gas Reporter, July issue. Harrison, S. S. 1985. Contaminati on 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 Pennsylvani a 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 me thane contamination of drinking water. Proceedings of the National Academy of Sciences, USA 103 :E872. King, G. E. 2012. Estimating frac risk and improvi ng 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 fro m hydraulically fractured shale to aquifers. Ground Water 50 :872-882. National Commission on the BP Deepwater Horizon O il 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 E nvironmental 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 Ma rcellus Shale Gas Development in Maryland

4-1 

### 4. Protecting water resources 1

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 am ounts of water are required for the process, and significant amounts of wastewater are pr oduced. Wastewaters (commonly called flowback and production waters) are contaminated with anthropogenic chemicals associated with the hydraulic fracturing process and with naturally-occurring chemicals as sociated with the shale formation. The possible impacts of shale gas development on regional wate r resources (i.e., quantity and quality) must be considered at all phases of the life-cycle of well and gas field de velopment. Figure 4-1 provides a life cycle representation for shale gas developm ent at a single pad. The general concerns for freshwater resources and the ge neration of wastewater are pres ented, aligned with when they occur in the life cycle of deve lopment. 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 chemi cals and preventing spills) are specific to activities that use large quantitie s of chemicals in the open, frequently under suboptimal climatic conditions. Finally, other co ncerns (e.g., concerns regarding casing and management of produced brine) are speci fic to oil and gas drilling operations.

A critical point shown in Figure 4-1 is that many poten tial impacts occur throughout development until closure (e.g., generation and ma nagement 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 th e level of the entire resource development (the play) that must also be consider ed. The distributed nature of the activity (i.e., potentially hundreds of locations in western Mary land) raises specific is sues with respect to watershed-wide effects. For example, it is importa nt 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 ma ny hundreds of wells are in production.

This chapter provides a summary of recommenda tions based on a review of the actual and proposed best management practices (B MPs) for shale gas development (MSGD 2 ) 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 Virg inia are applicable to Maryland, where geology, hydrology, and topography are very similar. Some practices that have been routinely employed in west ern states (e.g., evaporative con centration of wastes in open impoundments) are inappropriate for the mid-A tlantic region and cannot be recommended. We have also addressed some of the key re gulatory 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); Ke ith 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) Chapter 44-2PreDevelopmentPadDevelopmentDrillingCompletion viahydraulic fracturingProductionSite Closureand RestorationLife Cycle Phase

Fresh Water and Drinking Water Issues Waste Water IssuesWater withdrawals from surface andground water sources will occur.Alternative waters may be used(e.g., AMD, mine water, recycledproduced water).Fresh waterimpoundments andtemporary watertransport systemsmay be built on siteor in thedevelopment area.Ground water resources will be isolated fromdrilling and completion activities throughappropriate well casing.Surface water runoff may occur from stormwater and can affect fresh water resources at the surface and in aquifers. Erosion andsediment controls will be employed to collect stormwater for use or treatment on site.Fresh and recycled water will betrucked to the pad site.Produced water willbe stored on sitewith regularlyscheduled collectionvia truck.Water is used inchemicalmanufacture, sandextraction, andenergy generationnecessary toproduce theequipment andmaterials involved inthe process of shalegas extraction.Chemicals will be brought to the site.Produced water may be partially treated andreused on site.Temporaryimpoundments willbe closed. Storagetanks will beremoved.Drill cuttings will beremoved.Temporary chemicalstorage tanks will beremoved.Stormwater and surface runoff will generate wastewater. Erosion and sediment controls will be employed to collect stormwater foruseor treatment on site.Produced water willbe collected andtrucked to disposalor treatment.Early producedwater (flowback)will be collected andmay be treated onsite for reuse ortrucked off site forreuse, treatment ordisposal.Drill cuttings anddrilling muds will becollected for reuseor disposal.The well bore will besealed.Wastewater isproduced in chemicalmanufacture, sandextraction and energygeneration necessaryto produce theequipment andmaterials involved inthe process of shalegas extraction.Impoundment linersand residuals will becollected andtrucked to disposal.Partial reclamationof pad, includingrevegetation.Completereclamation of padand all developedarea.Removal of accessroads and pipelines.Chemical storagetanks and othertemporary facilitiesmay be built.Drilling and completion equipment willbe brought to the site and staged.12/6/2012Figure 4-1.Water and wastewater issues across the life cycle of pad and well development for unconventional shale gas development.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-3 

### A. Siting requirements: se tbacks and restrictions As discussed in previous and subsequent chapters , site selection for well pads and wells is an extremely important aspect of MSGD. The firs t 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 individua l wells: 70%), while 10% of the population uses communityprovided surface water. In Allegany County, tw o 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 thei r surface water. Three medium systems (Eastern Region Allegany, Lavale Sanitary Commissi on, 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, Midlothi an, Reckley Spring, and Rocky Gap) use groundwater, and one other sy stem (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 Pennsyl vania, part of the Evitts Cr eek 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 Geor ges Creek watershed (Potomac River watershed) and all fed by headwater streams. This surf ace water is supplemented by several groundwater wells that either pump into th e reservoir or the plant.

All public drinking water systems in Garrett C ounty are small: two systems (Friendsville and Oakland) are on surface water and three system s (McHenry, Mountain Lake Park, Grantsville) are on groundwater. Two very small systems (Bloomington and Kitzmiller) are on surface water, while the balance (Backbone M ountain, Crellin, Gorman, Mea dow Mountain, Meadow Park, Savage Mountain, Accident, Deer Park, and Wh ite Oak) are on groundwater. An additional 11 non-transient non-community systems and 75 transi ent 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 y ear. Further, source water assessment documents for Evitts Creek watershed indicate concerns with turbidity increases associated with rainfall events that would likel y be exacerbated if development did not include adequate sedimentation contro ls (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 systemsK.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-4 (Castro et al. 2001). As indicated by the asse ssment above, significant numbers of western Maryland residents rely on groundwater for their domestic water use.

Particularly in Garrett County, pr ivate well supply dependence (see Figure 4-2) suggests a strong need for setbacks and siting criteria that can eff ectively reduce the risks to these resources posed by surface spills (or incorrect drill ing 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 shou ld 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 a ffected 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 acci dental spills over a larg er 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 10 6 sq. ft.

Setbacks for public and private wells in curren t regulations are variab le, 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 Virg inia and Pennsylvania presently enforce 1,000 ft. setbacks to surface in takes and groundwater wells used for public water supply systems, but it has been recommen ded that New York impose a 2,000 ft. setbackRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-5 for public system intakes (NYSDEC 2011). Therefor e, 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 Virg inia have presumption of c ontamination rules for drinking water wells that contain contaminants after dr illing has taken place. Currently, the zone of presumptive liability is 1,000 feet. The Pennsyl vania Governor’s Marc ellus Shale Advisory Commission recommended increasing the liability zone to 2,500 feet from public water supply wells (Marcellus Shale Advisory Commissi on 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 increa sing the zone of liability to 3,000 feet from private water wells (Boyer et al . 2011). In 2012, the Maryland legi slature established a rebuttable presumption that drilling or fracking activities we re the cause of drinking water contamination if the contamination occurred w ithin 2500 feet of the vertical borehole and within 365 days 3 . Predrilling sampling is not required, and refusal of such sampling vacates the landowner’s right to compensatory damages. We support this regul atory structure and r ecommend that all water quality data collected through pre-drilling testing be provide d 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 requi ring post-development assessment of impacts to drinking water wells. These issues are di scussed further in section B below.

Due to the heavy reliance on impounded surface wate r from headwater streams in small, mostly forested watersheds as a drinki ng water source for the majority of Allegany County residents, water withdrawal plans and dril l pad siting plans should be as sessed within the context of watershed protection plans previ ously developed by the drinking water providers. Source water assessment and protection plans typically include source water delineatio n maps, transportation corridors, and existing potential so urces of water quality impairment information that can assist permitting and siting decisions. Any drinking wate r provider that does not have a watershed protection plan should be requi red to develop one in advan ce of any approved development within its source watershed. To avoid contaminati on 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 stagi ng and storage of hazardous materials and for eventual collection tanks for produced water. Setbacks from streams and wetlands are also recommended to reduce the poten tial for surface spills a ffecting source waters; consistent with recommendations in Chapter 6, a 300 ft. buffer fro m all streams, wetlands, and springs should be enforced to protect surface wa ter quality. As noted above, Ma ryland should enforce a 2,000 ft. setback from drinking water intake s for surface water plants to re duce direct contamination in the event of spills on site. Watershed protection plan s, 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 we stern 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 warrante d. 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 re sources prior to, during, and following development As discussed in section A above, routine pre-dr illing assessment of gr oundwater quality should be required in Maryland. Pre-drilling public no tification should also be part of the permit process, thus allowing well owners outside the pr e-drilling survey area to pursue their own water quality sampling, if desired. In Pennsylvania, citi zens have to ‘opt-in’ fo r notification of drilling in their area. Maryland should proactively publicize planned ac tivities during the pre-drilling phase of MSGD. The identificati on of all potentially affected gr oundwater wells and pre-drilling testing of these wells is a best management pr actice that should be re quired in Maryland. Predrilling testing should be required to be conducted by the operator a nd the results provided to the Maryland Department of the Environment and to th e well owner. Post-drilli ng testing is often at the discretion of the well owne r, but a best management prac tice that would enable improved understanding of the potential for effects on grou ndwater 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 comple tion 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 horizo ntal 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 s hould 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, strontiu m, naturally occurring radioactive materials (NORM), chemical oxygen demand (COD), and BTEX (benzene, toluene, ethylbenzene, and xylene). Curren tly, MGS tests for a wide variet y of natural and anthropogenic compounds in well samples (see Table 4-1). We reco mmend using this same suite of analyses for pre- and post-drilling sampling to provide the mo st comprehensive information on conditions in the subsurface and add to the repository of knowle dge in Maryland about gr oundwater resources.

We support the proposal that water samples be co llected by qualified professionals and analyzed utilizing an approved analytical laboratory (i.e., one approved by the Environmental Laboratory Accreditation Program, ELAP), in cluding the use of proper sampling and laboratory protocols in addition to the use of proper sample containers , preservation methods, ho lding times, chain of custody, analytical methods, and laboratory quality assurance/qual ity control (QA/QC) procedures (NYSDEC 2011). As not ed above, all data should be shared with MDE and MGS. In addition, Maryland should require full disclosu re of hydraulic fractur ing chemicals well in advance of their use (see Section I), thus en abling pre-development and post-developmentRecommended Best Management Practices for Ma rcellus 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 180 o 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-CH 4 (if sufficient methane available)
13 C-CH 4 (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 pote ntial to be affected by MSGD in Ma ryland. Drinking water providers in Pennsylvania and West Virginia have installed a network of source wate r 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 a nd finished water quality for consumers. RAIN is a collaborative effort among dr inking water plants, PADEP, We st Virginia Department of Environmental Protection (WVDEP), and USEPA, with joint funding for the sensors, deployment, and maintenance. RAIN should be ex tended into the Marcellu s development area in western Maryland, with funding provided to drinking water utilities to insta ll monitors near their intakes. Drinking water utilities have the tec hnical expertise to operate and maintain these sensors and can provide early no tification of any significant cha nges in water quality. Drinking water treatment plants operating in western Maryland should also increase their source water monitoring and specifically include bromide in th eir 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 sens ors can provide useful data for understanding assessing any impacts of MSGD on water res ources 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 base line characterization.



### C. Water pollution, stormwater ma nagement, and erosion and sediment control across the life cycle Development of shale gas begins as many other types of construction pr ojects do with clearing and leveling of land for the creation of a well pa d; additional cleared ac reage would likely be needed for roads, impoundments, pipelines, and utility corridors (see Chapter 1). One of the challenges for water associated with land clear ing is stormwater runoff from drilling pads, including erosion and sedimentati on and wash-off of any chemicals that have been spilled onto the pad during the various phases of an operation. R unoff of this type has the potential to affect downstream human water use as well as aquatic ha bitat, 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 managi ng 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 th e 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 th e National Pollutant Discharge Elimination System (NPDES) under which USEPA, or an authorized state agen cy, may issue permits th at 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-ba sed 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 a nd gas extraction facilities into surface waters are found in 40 CFR Part 35, Subpar t 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 di scharge 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 ow n authority to ensure that the “no discharge” requirement in the effluent guidelines is pr operly applied and that operator compliance is demonstrated 5 . The “no discharge” limit has obvious important implications for how the wastes (e.g., flowback, produced water, drilling muds, et c.) 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 regulat ions also address (1) indirect releases of wastewaters into U.S. waters such as by publicly owned treatmen t 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 Ma rcellus Shale Gas Development in Maryland

4-9 wastes; or (2) direct discharges from centralized treatment facilitie s that are subject to their own technology-based and water qual ity-based effluent guidelines.

The CWA also gives USEPA (and authorized st ate programs) the authority to regulate stormwater pollution under a separate NPDES permitting program. Impervious surfaces, such as buildings, homes, roads, sidewalk s, and parking lots, can signif icantly 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 ve locity 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, de bris, 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 su nlight reaching aquatic plants, clog fish gills, and smother aquatic habi tat and spawning areas. Therefore, the primary stormwater pollutant of concern from constructi on is usually sediment, and practices must be implemented to effectively control runoff and associated stormwater pollution. USEPA regulations require operators dist urbing one acre or more of land 6 (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-s pecific, written documen t 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 disc harges from the site; and (3) identifies procedures that an operator will implem ent to comply with the terms and conditions of a construction general permit. Pollution reductio n is most often achieved by controlling the volume of stormwater runoff (e.g., ta king steps to allow stormwater to infiltrate in to the soil).

As in point source permitting, Maryland is also authorized to issue coverage under the NPDES construction general permit for stormwater di scharges 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 polluti on, we believe there is a significant regulatory impediment to effective implementation of BM Ps to address stormw ater 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 ex empts 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 operatio ns associated with oil and gas exploration, production, processing, or treatmen t operations or transmission f acilities, includ ing activities necessary to prepare a site for drilling a nd 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/Stor mwaterManagementProgram/MarylandStormwaterDesign Manual/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx
8 40 CFR § 122.26 Storm water discharges.
9 Ibid., 5K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-10 equipment, whether or not such field activit ies or operations may be considered to be construction activities, except in accordance with paragra ph (c)(1)(iii) of this section. Discharges of sediment from construction activities associ ated 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 NPDE S industrial stormwater permitting, it is noted in the same statutes that the USEPA “encourages op erators of oil and gas field activities or operations to implement and ma intain best management practices (BMPs) to minimize discharges of pollutants, including se diment, in storm water both during and after construction activities to help ensure protecti on of surface water quality during storm events. Appropriate controls would be t hose suitable to the site conditions and consistent with generally accepted engineering design criteria and manufacturer specificati ons. 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 operations 12 that are not exempted from industrial stormwater permitting under the CWA, USEPA lacks the authority to regulate stor mwater pollution from oil and gas activities in the same way that it would do so for these othe r industrial activities. In Maryland, which is authorized by USEPA to do NPDES industrial st ormwater 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 cons idered “hotspots” for stormwat er pollution impacts, although they may meet the definition 13 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 cons truction, oil and gas operators are merely encouraged to implement BMPs to control stormwater pol lution and can be covered under the general construction permit 14 . USEPA and the approved state NP DES programs such as those in Maryland may be hampered in their efforts to c ontrol stormwater pollution from MSGD due to this exemption in federal law.

Other than consistency with the federal exem ption, 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 practic al implications for management of stormwater. Typically, at

10 40 CFR § 122.26(a)(2)(ii)
11 Ibid.
12 Including vehicle salvage yards and recycling facilities, vehicle service and maintenance facilities, vehicle and

equipment cleaning facilities, fleet storage areas, industri al sites, marinas, outdoor liquid container storage facilities, and outdoor loading/unloading facilities; s ee 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/Stormwat erManagementProgram/MarylandStormwaterDesignManu al/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx
13 A 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 stormw ater runoff, based on monito ring studies . See Maryland Stormwater Design Manual, Volume s I and II (effective October 2000, revised May 2009); Chapter 2.8 Designation of Stormwater Hotspots; http://www.mde.state.md.us/programs/Water/Stormwat erManagementProgram/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 Ma rcellus 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 infiltra tion into the ground as a primary means of reducing stormwater discharges and thus associated erosion and sedimentation problems. Performance standards developed in Maryla nd through largely urban stormwater control emphasize site designs that maximize pervious ar eas for stormwater treatment (standard no. 1) and promote infiltration through the use of stru ctural 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 differen tial requirements to prevent groundwater contamination. Since oil and gas development site s are more similar to hotspots than to urban development sites, Maryland should review its st ormwater regulations to ensure oil and gas extraction operations are managed in accordance w ith 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 “resto re 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 st ates 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 addres sed 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 an d 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 proced ures must be included in the state’s water quality standards (WQS). In addition, the federal rules 16 require that:

• Existing in-stream water uses and the level of water quality nece ssary to protect the existing uses shall be maintained and protected.

• Where the quality of the waters exceeds leve ls necessary to suppor t propagation of fish, shellfish, and wildlife and recreat ion in and on the water, that quality shall be maintained and protected unless the State finds, after full satisfacti on of the intergovernmental coordination and public participation provisi ons of the State's continuing planning process, that allowing lower water qualit y 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 St ate shall assure water quality adequate to protect existing uses fully.

• The state shall assure that there shall be achieved the highest st atutory and regulatory requirements for all new and existing point s ources 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/Stormwat erManagementProgram/MarylandStormwaterDesignManu al/Pages/programs/waterprograms/sedimentandstormwater/stormwater_design/index.aspx
16 40 CFR §131.12K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-12 • Where high quality waters const itute an outstanding national re source, such as waters of national and state parks and wildlife refuge s and waters of excep tional recreational or ecological significance, that water qualit y shall be maintained and protected.

Essentially, under federal rules, each state’s an ti-degradation policy must be implemented under a three-tiered program:

• “Tier 1”, that protects "existi ng 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 Sec tion 101(a)(2) goals (fishable a nd swimmable). Water quality may be lowered under certain conditions, but never below the level necessary to fully protect the “fishable and swimmable” and ot her existing uses [Sec tion 131.12(a)(2)]; and

• “Tier 3”, that are “outsta nding national resource wate rs” (ONRW) in which only temporary reductions in water qualit y are allowed [Sec tion 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 Ti er II implementation policy and promulgated a list of 87 Tier II (i.e., HQW) stream segments based on established crit eria of biological integrity; the majority of these Tier II segments are located in wester n 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 qu ality shall be maintained”. MDE will enforce the state Tier II policy by requiring that “applican ts for proposed amendments to county plans or discharge permits for discharge to Tier II waters that will resu lt in a new, or an increased, permitted annual discharge of pollutants and a potential impact to water quality, shall evaluate alternatives to eliminate or reduc e discharges or impacts”. A Tier II anti-degradation review is required for permits involving individual discharg es of at least 5,000 gallons per day; however, lesser proposed point discharges—and presumably non-poi nt source discharges—of pollutants that could potentially contribute to significant degradation of wa ter 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 developm ent cannot be permitted as discussed earlier, we do not believe that MSGD would trigger a Tier II anti-degra dation review in Maryland under current policy. For this reason, Ma ryland might wish to consider ways of strengthening its antidegradation policy to take account of the impact s of non-point source pollution that are a major threat to its high quality waters. One way that this might be accomplis hed would be by revising the WQS rules to require that any land devel opment practices (e.g., forest management, MSGD, etc.) conducted in Tier II watersheds meet an anti-degradation standard. 17

Based on review of stormwater management pr actices in other states, we recommend the construction of properly bermed “zer o-discharge” pads that effec tively collect all water on a pad site and enable the reuse of this water duri ng drilling and completion operations. This practice requires careful grading during th e 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 desi gned 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 Oreg on Department of Environmental Quality, 2010).Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-13 discharged from the pad, except for the entrance ro ad that should be elevat ed slightly above the pad to prevent runoff by the road. The entire pa d must be underlain with a heavy impervious synthetic liner (comparable to liners used by la ndfills). Any areas where mechanized equipment will operate should be overlain with a composite decking material to protect the liner from abrasion and prevent infiltra tion (Lien and Manner 2010).

Figure 4-3. Map showing locations of Tier II (i.e., HQW) str eams (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 (b erms, liners) stormwater pollution prevention measures. In Maryland’s seasonally wet climate, it’s likely that well pa ds would overflow once active management ends. Since personnel are only expected to be on si te continuously during active drilling and completion phases of developmen t of a particular well, it is imperative to consider how these pads will function after we ll 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 dr illing: (1) the pads c ould 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 manage d); or (2) the develope d area could remain disturbed and a stormwater collect ion and management system could remain in place. The best solution for addressing both quality (i.e., suspen ded solids) and quantity (i.e., peak discharge) issues would be through constr uction of a below-grade lined pond adjacent to the bermed zerodischarge pad that could be used as a sump during active stormwater management phases andK.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-14 easily converted into a retenti on pond prior to any passive phase s. 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 treatm ent could be obtained through operation of a constructed wetland sited dow nstream of the pond outlet.

Related to stormwater management, operators would be required to develop and implement erosion and sediment control plans. These plan s usually include BMPs for: (a) grading and stabilization to minimize erosion during deve lopment; (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 velo city 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 prev ent post-development chan ges in sediment loads from the site. Plans are typically certified by a registered profe ssional 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 developmen t of new roads to sites. Stream crossings and development through wetland areas should be avoi ded (see Chapter 6 also). In addition, as recommended for New York and Pennsylvania, the de sign of all stormwater control structures to address erosion and sedimentation should be ba sed on a 10yr/24hr rainstor m (i.e., the rainstorm with a duration of 24 hours that occurs, on aver age, once every ten years), as opposed to the 2yr/24hr storm that occurs more frequently. Give n the complexities in addressing how active and passive stormwater management will occur, we al so recommend that the state ensure that Soil Conservation Districts, which cu rrently review and approve sedi ment control plans and who are most knowledgeable for their geographi c area are on-site during all major construction/deconstruction activitie s. 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 regulati ons 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 pu blished by Maryland in February 2012 (MDE 2012). The model ordinance incl udes 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 (E SC) plan review is required prior to permit approval. This is ideal and s hould be retained (some state regulations have exemptions that pertain specifica lly to oil and gas development 18 ). Garrett and Allegany County should follow the Model Ordinance proposed by MD E, but should also requi re consideration in ESC plans of the potential effects of multiple clea rings in relatively close proximity. Exemptions for small sites should not be enacted. Maryland s hould also evaluate poten tial 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 “Perm it Application for Drilling or Altering a Well” (5500- PMOG0001) is sufficient. An Erosion and Sediment Contro l 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 c ontrol requirements at one acre or greater under the Pennsylvania Chapter 102 requirements and NPDES requirements.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-15 with stormwater, sedimentation and erosion wi thin 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 managi ng potential impacts on downstream water users. Maryland should ensure that public water s upplies 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 docum ent entitled “Guidance Document, Reasonable and Prudent Practices for Stab ilization (RAPPS) at Oil and Natural Ga s Exploration and Production Sites” published by API. The latter report describes a host of specific operating practices and control measures that have been us ed and tested by oil and natural gas operators to effectively control er osion and sedimentation from stor mwater runoff resulting from land clearing, grading, and excavation operations at explor ation 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 drille d lateral. To support MSGD, water can be extracted from surface or groundwater sources (inc luding 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 importa nt to keep it in cont ext 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 aver age 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 equiva lent to the amount of water required to develop about 3,500 Marcellu s shale gas wells in the state.

There are very long gage records av ailable 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 av erage discharge in these three rivers is 635 MGD—producing a volume of water on an average da y that is more than 100 times larger than the water requirement to develop a single Marcellu s shale gas well. However, it must be noted that the average discharge of wate r in these rivers varies drama tically 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 on ly 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 time s under all conditions. On the other hand, underK.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-16 average conditions and particularly at the highe r discharges normally re ached during the spring of the year, the data suggest th at there may be adequate suppli es provided by western Maryland’s major rivers as source water for MSGD.

With respect to groundwater sources, in Chapte r 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 assess ment processes. Much of that information is clearly relevant to identifyi ng 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 formati ons (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 c onsidered the principal aquifers , but wells completed in these formations commonly yield less than 120 gallons pe r minute; wells in limestone formations of late Silurian through early Devonian age may lo cally 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 Ma ryland’s groundwater resource could potentially be exploited to support HVHF, but research woul d be needed to assess whether such development would likely cause the safe yi eld of these aquifers to be exceeded. We can envision that groundwater could pl ay a role in supplying hydrau lic fracturing operations during dry summer periods when water levels in majo r rivers and reservoirs are too low to permit surface withdrawals, or cases wh ere a particular well pad (1) is located an excessive distance from a permitted surface water s upply location; or (2) is not e fficiently 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 pi peline) a group of multi-well pads that were part of a clustered development (see Ch apter 1), with the caveat that th e 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 MSGD 19 —presumably due to limited supplies, low well yields, and high costs (compared to the surface water a lternative). 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 Maryla nd would be primarily supported by available groundwater resources.

In Maryland, both surface and groundwater withdrawal s are regulated by MDE. 20 Permit approval requires that the appli cant provide satisfactory proof that the proposed withdrawal of water is reasonable and the impacts on the water re source and other users are acceptable. Further, the proposed use must be consistent with loca l 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 da y, and public notification may be required.

19 Recent data provided by SRBC to MDE indicates that Marc ellus operators in Pennsylvania have obtained permits

to supply 4% of their total water needs from groundwa ter 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.pdfRecommended Best Management Practices for Ma rcellus 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 “Criteri a for Approval of Water Appropriation or Use Permits” 21 , provides narrative regarding reasonableness, including a cons ideration of: (a) the purpose of the use; (b) the suitability of the use to the watercourse, lake or aquifer; (c) the ex tent and the amount of harm it may cause; (d) th e practicality of avoiding the harm by adjusting the proposed use or method of use of the applicant or another permitt ee; (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 stat e; (g) the contribution that the proposed appropriation may make to future degrad ation of the waters of the state; and (h) whether the proposed appropr iation or use is located within a water management strategy area.

For surface water sources, appr oved withdrawals are “conditioned on the maintenance, by the permittee, of a required minimum flow past the poi nt of appropriation to protect other users of the water and to protect flora a nd fauna within the watercourse. 22 ” The most common required minimum flow is typically set at the lowest 7 da y average in the past 10 years (Q7-10). The Q7- 10 is specific to each source wate r 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 rest ricted flow point, for example, when the flow is less than 20% of the average daily flow. Fo r gaged streams, average daily flow is easily determined; however, for ungaged streams, a refe rence gage approach using USGS regression tools is required. Significant unc ertainty is often observed in su ch 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-speci fic historical gage data will provide a clear assessment of the most appropriate method for fl ow prediction in ungaged streams in the state. We are confident that there are adequate long-t erm and site-specific data for a sufficient number of gaged watersheds to support a rigorous analys is of stream discharges in western Maryland watersheds to inform an analysis of minimum re quired 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 experien ce in Maryland watersheds as well as review of other areas that have completed such analys is, suggest that in western Maryland, water withdrawals for proposed MSGD will need to occu r solely from the region’s large rivers (and perhaps from one or more reservoirs). Small st reams (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 resour ce and other users are acceptable” can be even more challenging than determining minimum requi red 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 re quire the permitee to assess th e cumulative net withdrawals upgradient of the proposed new w ithdrawal, 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 26.17.06.05K.N. Eshleman & A.J. Elmore (2013) Chapter 4

4-18 related to water withdrawals as shale gas drilli ng has expanded throughout the Susquehanna and Ohio River basins. Several critic al reviews have been completed that should be considered as Maryland decides how to update water withdr awal permitting processes to consider the temporally and spatially distribut ed withdrawals typical of this industry. For example, the TNC Ecosystem Flows Study (TNC 2010) was a colla boration between The Nature Conservancy (TNC), the Susquehanna River Basin Commission (SRBC) and the United States Army Corps of Engineers (USACE). This study focused speci fically on the Susquehanna River and its tributaries; however, the approach and general conclusions provide important information for MDE in assessing ecosystem considerations for st reamflow and the role of this component in water withdrawal permitting for shale gas development.

Recently, as part of proposed changes to th e Low Flow Protection Policy of SRBC, MDE expressed concerns regarding the use of a fixed ‘de minimus’ threshold for headwater watersheds and highly sensitive wa tersheds since this ‘de minimus’ characterization is not used in Maryland statute (Kasraei 2012). As MDE notes in their re sponse to SRBC, “it may not be feasible to appropriate ly quantify the flow regimes of cer tain ungaged smaller systems due to lack of relevant data” and othe r site specific conditions. As disc ussed above, the difficulty in assessing the impacts of water withdrawals w ith insufficient gaging data is well known (Murphy et al. 2012, Razavi and Coulibaly 2012, Shu and Ouarda 2012) and we st rongly recommend that water withdrawals for MSGD be encouraged from larger rivers (and perhaps existing reservoirs). MSGD should totally avoid small headwater st reams and watersheds out of concern for dewatering of these sensitive systems. Specific rath er 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 st orage will be necessary to enable continued operations during the dry periods when withdrawal s are likely to be limited. The size and number of any centralized water impoundments and pipeli nes constructed to supp ort industry operations is often predicated on the stability of water s upply. When water supplies are restricted for more of the year, gas development operations will e ither 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 with in 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 likel y reduce the number of impoundments and withdrawal locations and enable smaller facilities, while still pr oviding adequate and stable water supplies. Water management plans, in addition to water withdrawal perm its, should be required for all drilling activities to ensure that de velopment activities inco rporate water resource planning. Coordinated multi-opera tional water provisioning should be planned to reduce the disturbances associated with impou ndments and water withdrawals.Recommended Best Management Practices for Ma rcellus 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 wate r within a watershed, often at the hydrologic un it code (HUC) level of 1 (i.e., HUC 2). This level is typica lly hundreds of thousands of square miles and usually involves multiple states. HUC 2 wate rsheds are often managed through interstate compacts. Maryland participates in several ba sin 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 wher e shale gas is found, however. Fi gure 4-4 shows the extent of relevant basins in Maryland.

A portion of western Maryland within Garrett County is part of the Ohio Ri ver Basin (part of the larger Mississippi River Ba sin). The Ohio River Basin Commission was founded in 1981; however, the organization no longer operates, an d it does not assert authority over water withdrawals within the basin. The Ohio River Valley Water Sanitation Commission (ORSANCO) is an interstate co mmission (established in 1948) charged with management of
water quality in the Ohio River and its tributarie s. 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 recreati onal reservoir that be gins in Maryland and continues into southwestern Pennsylvania. Seve ral groups have recommended the creation of an Ohio River Basin Commission that would manage water withdrawal s to ensure water quality and protection of aquatic resources, especially during low flow cond itions in the region (generally summer time) and ORSANCO is currently evaluati ng 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 Pe nnsylvania, providing important dilution of the main stem of the Monongahela River that travels north from West Virgin ia into Pennsylvania, terminating at its confluence with the Allegheny Ri ver to form the Ohio (at Pittsburgh, PA). Changes in the water quality within the Y oughiogheny River would affect downstream water users in Pennsylvania.

A major portion of Garrett Count y is part of the North Bran ch Potomac (0207002) watershed. Allegany County is located with in the South and North Bran ch of the Potomac (0207001 and 0207002) and the Cacapon-Town (0207003) subwater sheds. 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 IC PRB 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, comprehensiv e 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 reco mmend 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 al so discuss the operational conditions of Youghiogheny Reservoir, Savage River Reservoir, and Jennings Randolph Lakes with USACE to evaluate these systems as pot ential sources of water for MSGD, particularly during high flow conditions when recreational and other us es 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 pa d to support the hydrauli c fracturing operation. During active development of the site, through drilling and the hydrauli c 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 ta nks 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 pr oposed and are currently being ut ilized that reduce or eliminate truck traffic and decrease the si ze of well pads. In the Pennsylvani a state forests, freshwater is being moved from centralized storage facilities to active location(s) throu gh the use of temporary piping. This practice significantl y reduces the frequency of heavy hauling across state forest roads, minimizes the possibility of vehicula r conflicts, and decrease s 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 ex isting infrastructure, including stormwater structures (e.g., culverts). Where applicable, buried piping should minimize additional earth disturbance and be co-located with natural gas pipe lines, 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 Pennsyl vania, 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 c onstructed in reasonably close proximity.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-21 Freshwater delivered by either tr ucks 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 a nd 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 fo r these impoundments would be dictated by topography (i.e., suitable, reasonab ly flat locations where they can be constructed). Maryland has existing pond standards/specific ations related to livestock wa tering, recreation, agricultural storage, and stormwater management (MDE 2000), but no specific standards exist for storage of water for oil and gas development. We recomme nd 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 impoundment s be discharged into any Maryland streams and rivers due to concerns for introduction of exotic species (e.g., gol den algae) and impacts on water temperatures. As discussed in Secti on 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 wa ter 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 disc ussed alternate source is acid mine drainage (AMD) that is commonly discharg ed throughout the Marcel lus shale region. Ma ryland 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 deri ved) could serve as alternate, non-potable water sources for MSGD. Among othe r known AMD sources is the outflow from the Hoffman Drainage Tunnel (HDT) near Clarys ville, MD that typically discharges into Braddock Run (a tributary of Wills Creek) at a ra te of about 7.3 MGD (recently reported range is 7–30 MGD)—making this source a candidate to be evaluated as an alternate water source 23 . As discussed by one recent report, the use of AMD-im paired water or treated wastewater could have overall positive benefits on wate r quality through removal of these inputs from receiving streams (Lien and Manner 2010). We must note, however, th at 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 re ceiving stream that exceeds by more than an order of magnitude the natural fl ow regime. HDT discharge also allows Braddock Run to support a brook trout population 24 , despite the fact that the discharge is obviously laden with ferric hydroxide—commonl y known as “yellow-boy”.

Nearby West Virginia and Pennsyl vania have even more extensiv e 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 in to surface waters (e.g., Hansen et al. 2010). Similarly, active coal mines and coal bed methan e extraction activities ge nerate high volumes of water during dewatering activities that are ongoing for the durati on 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 2 010). Treatment is generally necessary for use of AMD-impaired waters in hydrau lic fracturing, with removal of sulfate as a crit ical issue to prevent formation of barium sulfate precipitate s 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 wate r. Other industrial wast ewaters may also have potential to be repurposed fo r 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 lia bility 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 expresse d significant interest in use of AMD-impaired waters, but they do not want to be liable for cleanup of the c ontinuing 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 Co rporation 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 evaluati on of quantity and quality available across a region, and a collaborative approach among regul ators, industry and ot her stakeholders to develop and analyze technical concepts and implementation mechanisms. Clearly, a best practice would be for Maryland to conduct a fe asibility 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 im portant 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 eval uate any regulatory limitations that would interfer e with beneficial repurposing of mine water for hydraulic fracturing.



### H. Chemical delivery, stor age on-site, and transfers Chemicals will need to be delivered and stor ed on site prior to drilling and completion operations. Some of these chemicals are hazardou s and attention must be paid to their proper management. Closed storage tanks are necessary fo r 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 Ma rcellus 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, in cluding 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 list ed 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 Mate rial Data Safety Sheets (MSDS) s hould 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 ap propriate toxicological data, chemical characterizations, MSDS, and sp ill clean-up procedures) should be included in permit applications. It must be kept in mind th at MSDS may not contai n 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 sp ill or other emergency, however.

Drillers report using fewer chemicals for MSGD th an 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 ch emicals) 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 consider ed best practices. Closed-loop dril ling 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 w ith 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 polym er 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 fe deral statutory exemption under RCRA and are, therefore, not categorized as hazardous wastes , they should be manage d 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 cuttin gs 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 bac kground levels. State action levels for NORM range from 5-30 picocuries per gram (pCi/g) of to tal radium and levels c onsidered to represent ‘uncontaminated’ materials are often set at twice the background le vel (NYSDEC 1999). As discussed in more detail in S ection 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 prod uced waters and wastewaters Once drilling and completion have taken place, produ ced water will begin to be generated from the well during the flowback period, and late r 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 produc tion (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 di stinction is desired, for example, because flowback may be higher quality (l ower 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 wa stewaters at the development s ites is precluded by federal law 25

, 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 sh ale gas plays and even in different wells in the same formation. Typically 10-25% of the injected water retu rns to the surface as flowback during the preproduction phase (Hayes and Schroeder 2009). Marc ellus 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 th e 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 ad equate secondary containment). Secondary containment (including dikes, line rs, pads, curbs, sumps and other relevant structures) should be employed to minimize the potential for accidenta l releases of production wastes from these containment facilities.

Despite the challenges associated with on-site ma nagement of large volumes of produced water, recycling this water for use in subsequent hydrau lic fracturing operations e ither on the same site or at another site is an obvi ous best practice. Water produced in the flowback period can be stored on-site for use in a subsequent completio n 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 produ ced water for subsequent reuse in hydraulic fracturing and encourages 100% recycling for wate r produced at well pads under development. It is not clear how such water is tracked or repor ted in Pennsylvania, but most large companies report nearly 100% recycling of early phase prod uced water (i.e., flowback) (Grottenthaler 2010,

25 40 CFR §435.32.Recommended Best Management Practices for Ma rcellus 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 mana gement 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 lo gistical challenge, alt hough 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 gallo ns 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 pr oduced water, however this management option will not be economical if newer drilling pads ar e sited long distances from existing producing wells. This may not be a huge problem in Ma ryland, 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 Pennsylva nia where centralized treatment plants offer partial treatment of produced water (remova l of everything except monovalent ions: Na + , Cl -
, Br - ) with return of the highly sali ne water to the well pads for reuse. Maryland should include a strong preference for reuse of produced waters fo r 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 (inc luding recordkeeping, manifesting) As noted in Section K, there is no generall y accepted definition of flowback and no legal definition that distingu ishes between flowback and produced water. Best management practices should not attempt to distinguish based on these imp recise classifications but rather should refer to water quality characteristics if distinct hand ling 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 fr om the original hydraulic fracturing fluids. Produced waters generally become more concen trated in salts over pr oduction 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 RCRA 26 . As a non-hazardous waste, oil and gas production wastes are subject to different requi rements for generation, transpor tation, treatment, storage and disposal. Maryland has been authorized by the US EPA 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 federa l 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 Hazar dous Waste; 40 CFR 26 1.4(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, however 27

. 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 cr iteria 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 no t reported to any regulator y agency, nor are they necessarily kept beyond the deci sion-making process. Trucks tr ansporting any wastewater are required to carry manifests regarding their car go, but are not required to be placarded as hazardous. Maryland should review its requirement s for testing and manifesting of hazardous and non-hazardous waste to determine which regulat ory structure applies to oil and gas produced
wastes.

Volumes of produced water from each well are ge nerally reported on regul ar 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 Pennsyl vania the location of the reuse is not specified. These reports are tabulated in Pennsylvania and released to the public (via a we b 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 ar e for which wells) and insufficient detail on the reuse of flowback and produced water within multip le wells prior to ultimate disposal. In West Virginia, additional transportation records are re quired that might allow tracking of water from original withdrawal to final di sposition, although the state does not undertake to evaluate water use and wastewater generation in this way. Mary land should require reporting of produced water volumes from every well, including the well lo cation, 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 residua l fracturing chemicals, this is not permitted for early produced water (i.e., flowback), but is co mmonly practiced with the low volume, high salt water that returns during the production phase. Spreading on ro ads within the oil and gas development region (often dirt roads create d by the drilling companies), as well as in surrounding rural areas, is not uncommon. In Pennsyl vania and West Virginia this activity is permitted for certain brines. Clearly, surface applicati ons 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, particul arly 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 treat ment facilities have suggested the creation of a

27 COMAR 26.13.02.04-1A(5)Recommended Best Management Practices for Ma rcellus 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 appropri ate for liquid residuals from treatment operations (e.g., highly concentrated brines). We discuss this option further in section N below, but it is unlik ely to be used in Maryland.



### M. Treatment of produced water 28 Produced water can be treated using a variety of chemical and physical processes to remove contaminants. Generally, radionuclides and multival ent metal ions are relatively easy to remove through coagulation, precipitation and filtrati on. 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-intensiv e. Concentrations of salt in produced water from the Marcellus formati on in Pennsylvania and We st Virginia are too high for membrane systems such as reverse osmo sis; therefore, therma l 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 concen trated brine solution or a soli d salt product as a residual. These residuals must be managed while the desalinate d 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 ty pically take place off-site. Produ ced water is picked up from a number of wells in tanker truc ks on a regular schedule and taken to a centralized brine treatment plant. There are no permitted centralized brine tr eatment plants currently in Maryland. However, there are plants in West Virgin ia and Pennsylvania, and additiona l plants have been opening in response to additional produced water volumes re quiring management. Two types of plants are operating in Pennsylvania. A few brine treatment plants that were opera ting before regulatory change to discharge standards on salt continue to operate without TDS limits for their discharge. These plants remove most contam inants except monova lent ions (Na + , Cl - , Br - ), and discharge the residual high salt brine to surface waters (creeks and rivers). However, these surface discharging plants no longer re ceive Marcellus formation pr oduced water as the PA DEP requested that drillers stop usi ng 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 critic al drinking water areas, prior to approving brine treatment plants, Maryland should enact a discha rge 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 f acilities into the waters of the state. Further, development of brine treatment plants that recy cle water to drillers shou ld be discouraged in favor of on-site treatmen t 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 Penns ylvania and West Virginia do not discharge wastewater to the environment. They treat produc ed water to remove metals and organics, and return the brine containing only mo novalent ions to dr illing companies for reuse. This is very similar to the on-site partial treatment for reuse discussed in Section K. Because this treatmentrequires 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 wate r 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 plan s 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 wate r 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 regul atory hurdles remai n. 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 wa ter was used. Produced water was sent to conventional wastewater treatment plants, clas sified by USEPA as publicly-owned treatment works (POTWs). These plants treat domestic se wage and are not designed to remove chemicals from oil and gas brines. However, relatively larg e 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 flow s 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 implicat ions for drinking water treatment, rose as well. The PA DEP intervened in 2008 and 2009 to restri ct use of POTWs for brine treatment. USEPA has also provided clarifications regarding the acceptance of oil and ga s wastewaters and made substantial changes that required permit modifications 29 . In 2011, PA DEP requested that Marcellus wastewater not go to any surface-discha rging POTWs without a TD S 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 changes 30 . In addition to Pennsylvania, Ohio is co nsidering use of POTWs for brine treatment and disposal, and several lawsuits surrounding th is situation are pendi ng in that state.

Following concerns regarding the use of POTWs, often without pretreatment of the produced water, the USEPA announced plans to devel op 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-treatmen t 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 Ma rcellus 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 exampl e, 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 fr om 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 dr inking water sources should not be permitted. This activity impedes treatment of water to provide wate r that is potable and safe for consumers. Higher chloride levels cause tast e and odor problems in finished wa ter. High bromide levels lead to increased formation of carcinoge nic 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 rem ove 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 rela ted to hazardous waste, provided the exempt waste is not mixed with a non-exempt wast e prior to the treatment process 31 . Maryland has not objected to the ‘derived from’ interpretation in RCRA th at exempts residuals produced from exempt wastes. Treatment residuals will contain rem oved contaminants such as NORM, heavy metals, organic compounds, and salts, and th ese 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 dis posal 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 inje ction in Underground Injecti on 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 no t have an extensive deep we ll injection infrastructure. Pennsylvania has only a few UIC Cl ass II wells that are mostly pr ivately owned. West Virginia and Ohio have considerably more such fac ilities, 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 earthquak es associated with underground injection have also limited the new c iting of commercial disposal wells. Maryland does not have a single UIC Class II disposal well. At present, dis posal through deep well injection will require either trucking wastes to neighboring West Virg inia or siting, permitting and drilling injection wells w ithin Maryland. Maryland may prefer to develop UIC Class II injections wells to avoid long distance trucking of produced wa ters. However, these wells are commonly sited in played out areas of gas deve lopment, which Maryland does not have, or in areas that are also suited for gas storage, whic h Maryland is currently us ing 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 siti ng injection wells may be very limited. Review of injection well concerns in ne ighboring states and geological survey of Maryland subsurface formations should be undertaken prior to consid eration of this activit y in Maryland. Further, Maryland should review the rele vant regulations surrounding deve lopment and use of UIC wells for produced water from shale gas development, a nd 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 cl osure (decommissioning) In general, once production begins, interim reclam ation 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 with in 60 days of the initiation of gas production, and the operator should submit a si te restoration report to the stat e. Interim reclamation of the site after completion restores the disturbed la nd but allows continual access for collection of produced water, transport of gas (via gath ering pipelines) and access for any future well reworking, if necessary. Road access must be mainta ined, but other areas of the site that were disturbed for heavy equipment needed during dr illing and completion should be regraded and revegetated. All solid wastes shou ld be disposed of using methods appropriate for the waste type, following state regulations. Residuals from gas dr illing activities should be evaluated for their constituents to determine their status as h azardous wastes and managed accordingly. Water storage impoundments should be cl osed and these disturbed areas reclaimed. Pit liners should be removed and landfilled off-site. On-site dis posal of residuals should not be permitted. Stormwater management for contro l 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 (esp ecially as the first wells are drilled and the productive capacity of these wells is ascertain ed) and some of the ramifications for such a process from the standpoint of interim recl amation. 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 re gulations 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 site s 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 de velopment takes place w ithin 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 si te should take place. As discussed in Chapter 3, this requires plugging the well to ensure is olation 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 uni ntended losses of the gas resource). Permanent signage should be left in place to allow the we ll 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 ar eas, including recontouring to reestablish the original topographic cont ours, 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 na tive vegetation (or pre-di sturbance vegetation inRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-31 the case of agricultural land re turning to production) and rest ore the original hydrologic conditions to the maximu m extent possible.

Improperly closed wells have led to significant environmental impacts in oil and gas states in the past (including Pennsylvania and West Virginia 32,33 ) and thus should be avoided. Detailed, proscriptive methods for well closure should be developed th rough review of industry best management practices and other state regulati ons (see Chapter 3). Maryland should take a proactive approach to re gulation in this area. With the implementation of best practices in well closure, Maryland should be able to avoid the problems that ot her states have experienced throughout their long oil and ga s development histories.



### P. Naturally occurring radi oactive materials (NORM) Shale gas formations often contain naturally-occ urring radioactive materi als (NORM) and drill cuttings and production brines can contain NORM. NORM should be assessed in all components of waste associated with gas production from sh ale. 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 back ground at most oil and gas production sites. Similar monitoring should be rout ine at MSGD sites to ensure ad equate 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 ex emption of oil and gas production wastes 34

. Similarly, when drill cuttings and production wast es are treated or disposed of, residuals from these processes can become en riched in NORM (then called t echnologically-enhan ced, naturallyoccurring radioactive materials or TENORM). Th is enrichment process should be monitored and, if necessary, residuals should be reclassified as radioactive waste (RW) to ensure they are tracked and protective disposal pr actices are used. All drilling wast es should be evaluated for the presence of NORM to ensure adequate disposal. Pennsylvania landfills ha ve utilized radiation detection systems to ensure that radioactiv e 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 soli d waste disposal landfil ls for radioactivity.

If NORM or TENORM waste associated with oil a nd gas production or waste treatment contains levels of radioactivity that would result in clas sification as low-level radioactive waste (LLRW), these residuals should be treated in accordan ce with LLRW regulations. LLRW generated in treatment of produced water from MSGD in Maryla nd would likely be disposed of outside of the state. The Appalachian States Low-Level Radioac tive 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 Versa illes, Pennsylvania. Available on the web at:

http://www.netl.doe.gov/n ewsroom/versailles/Versailles%20 Methane%20Emissions%20Project%20- %20Final%20Report.pdf
33 PA 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/s ubject/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 Commissi on identified Pennsylvania as the host state to receive and dispose of radioactive waste from the party stat es (Delaware, Pennsylvania, West Virginia and Maryland). Maryland producers of LLRW can also c ontract with out of st ate facilities through approval by other interstate comm issions (e.g., Texas compact).

Gas operations are typically short term and t hus, build up of NORM at a given site is not expected; however, equipment is moved from site to site and coul d develop scale that incorporates NORM. Oil and gas production equipmen t should be assessed at regular intervals. Tanks on-site holding produced water could also develop precipitates with time that contain NORM. Regular inspections and clean ing 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 estab lishment in regulation of 500 ft. and 2,000 ft. setbacks (measured from the well pad, not fr om the individual wellbores) for private wells and public system intakes (bot h 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 ow ner. Post-drilling tes ting is often at the discretion of the well owner, but a best mana gement practice that would enable improved understanding of the potential for effects on groundwater would be to require postdrilling and completion testing by the operato r for all wells within a pre-determined potentially affected region for a speci fied time period after completion of well construction activities.

3-D Maryland might wish to consider ways of strengthening its anti-de gradation policy to take account of the impacts of non-point sour ce pollution that are a major threat to its high quality waters. One way th at this might be accomplis hed would be by revising the WQS rules to require that any land devel opment practices (e.g., forest management, MSGD, etc.) conducted in Tier II watershe ds meet an anti-degradation standard.

3-E Maryland needs to carefully review its stormwat er regulations as they pertain to oil and gas extraction; we recommend oil and gas extr action sites be considered “hotspots.” Based on our review of stormwater manageme nt practices in othe r states, we recommend the use of both “active” and “passive” stormw ater management: (1) the construction of properly bermed “zero-discharge” pads that eff ectively collect all water on a pad site and enable the reuse of this water during dr illing and completion operations; and (2) construction of a below-grade lined pond adjace nt 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 Ma rcellus Shale Gas Development in Maryland

4-33 3-G There are very long gage reco rds available from USGS for most of the major western Maryland rivers (Youghiogheny, Casselman, Sa vage, 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 s hould 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 pe rhaps from one or more reservoirs). Small streams (1) have significant existing withdrawals for dri nking water; (2) have small catchment areas and discharges under most conditions; (3) are very unlikely to have excess flow capacity for new permitted withdraw als; 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 chemical s to be used on site (plus appropriate toxicological data, chemical characteriza tions, 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 pr actice for Maryland.

3-J Maryland should include a very st rong 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. Deve lopment of brine treatment plants that recycle water to drillers should be discouraged in fa vor of on-site treatment by mobile units and immediate reuse as this decreases truc k transport and associated impacts.

3-K Maryland should review the relevant regulations surrounding development and use of underground injection wells for produced wate r from shale gas development and, at the same time, evaluate the capacity of near by states to accept produ ced 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 enviro nmentally suitable fracturing fluids using hydraulic fracturing flowback waters. SPE Unconventiona l Gas Conference, Pittsburgh PA, Society of Petroleum Engineers. Boyer, E. W., et al. 2011. The Impact of Marce llus Gas Drilling on Rural Drinking Water Supplies, Pennsylvania State University. Castro, M. S., et al. 2001. Water Quality Assessmen t of the Piney Creek Reservoir and Watershed in Western Maryland. A. L. University of Maryla nd Center for Environmental Sciences, Report for Maryland Department of Natural Resources. Curtright, A. E., and K. Giglio. 2012. Coal Mine Dr ainage 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: De tailed 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/gui de/upload/shalereporterfactsheet.pdf. Grottenthaler, D. 2010. Cabot gas well treated w ith 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. Ne w 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 Stre ams 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 Comm isssion 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 improvi ng 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 fo r 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. [Penns ylvania] 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-Occurri ng 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 E nvironmental Impact Statement on the Oil, Gas, and Solution Mining Regulatory Program. PADEP. 2003. Evitts Creek Source Water Assessment, Pennsylvania Department of Environmental Protection : 2.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

4-35 PADEP. 2012. Monitoring for Radioactive Materials in Solid Waste. Retrieved November 27, 2012, from http://www.dep.state.pa.us/brp/Radiation_Cont rol_Division/SolidWasteMonitoring/SolidWasteR adMonitoring.htm. Razavi, T. and P. Coulibaly. 2012. Streamflow predic tion in ungauged basins: re view 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 De velopment. 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 U sed 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 Ma rcellus Shale Gas Development in Maryland

5-1 

## 5. Protecting terrestrial habitat and wildlife 1

Despite high levels of development in many area s of the state, western Maryland (Allegany and Garrett County) remains a largely intact landscape relativ e to other regions of the eastern United States 2 . The dominant land cover type of the Appa lachian mountains of western Maryland is forest (>75%; Figure 5-1), includi ng extensive areas of forest in terior 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 la nd 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 fore sts are of equal value, and rare or sensitive forest habitat should be avoide d. Beyond the direct loss of hab itat, many species in western Maryland are potentially sensitiv e to new construction that re duces the amount of core and connected habitat, creates opportunities for di rect 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 plan ts are currently listed as rare, threatened, or endangered within Maryland' s Marcellus Shale region (A ppendix 5A). Many of the recommendations in this chapter are aimed at minimizing the fragmentation of the forested landscape with special emphasis on protecting irreplaceable habita ts and imperiled terrestrial biota. Forest protection is al so protective of downstream aqua tic 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 c onsistent with the state's overall resource stewardship and a useful guiding prin ciple 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 fo rest loss is appr oximately twice that of the overall forest loss (Slonecker et al. 2012). Another recent study in Pennsylvania found that Marcellus well pads and associated in frastructure (roads, water impoundments, and pipelines) required approximately 9 acres per well pad with an additional 21 acres of indirect edge effects 3 . 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. (Depar tment Geography and the Envi ronment, 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 ener gy impacts assessment, Report 1: Mar cellus Shale Natural Gas and Wind, The

Nature Conservancy, Pennsylvania Ch apter, and Pennsylvania Audubon, http://www.nature.org/wh erewework/northamerica/states/p ennsylvania/news/news3511.html.K.N. Eshl e

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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 comm unities in a developed landscape. 6
Unfortunately, Allegany and Garrett County are currently exempt from the Maryland FCA because of their high percentage s of forest land-cover and per ceived 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. Ther efore, Maryland should consider adopting a no-net-loss of forest appr oach 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 co nservation 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 environm ental impact of more than one project to be considered at the same time (Strong 2008). A sma ll project may not have a negative impact on habitat alone, but when considered in the cont ext of nearby or related projects, the negative impact may be significant. With respect to terr estrial 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 fo rest 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 tr ansfers, and is one of the biggest threats to wildlife from hydraulic fracturing operations (Thompson 2012). Although many of the chemicals contained in hydraulic fracturing fl uids are potentially toxic to w ildlife, 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 clos e to active gas-drilling operations (Oswald and Bamberger 2012), with seve ral 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 aer ators) and misted into the ai r creating an inhalation exposure pathway, the most common source of toxicity ex posure was likely via contaminated water. Pathways of exposure included, for example, spills of hydraulic fracturing fluids, tears in the liners of wastewater impoundments, and spreadin g of wastewater on roads to reduced dust and ice followed by animals licking their paws after cr ossing 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/dnrn ews/pdfs/NNLTFFINALREPORT1.pdfRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

5-5 ranged from neurological to sudden death with the most common effect s being reproductive. Animals affected include cows, horses, goats, lla mas, 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. Additi onally, 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 ponds 7

. 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 li quids should be stored inside storage trailers (PADCNR 2011). Closed storage tanks with seco ndary containment should be used for all storage of chemicals and produced waters, especial ly 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 featur es and freeboard of several feet should be maintained. The construction of any impoundment s 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 pr oduced 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 Bi rds. 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 3K.N. Eshleman & A.J. Elmore (2013) Chapter 5

5-6 

### C. Riparian setbacks Forested riparian buffers enhance biodivers ity by (1) providing fo raging, nesting, brooding, thermal, and escape cover; (2) protecting sens itive habitats; and (3) maintaining landscape connectivity (Bentrup 2008). These te rrestrial habitats also provide valuable buffer benefits to aquatic environments, for example, by shading streams to maintain favorable temperature (Moore et al. 2005). Despite strong ev idence 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., am phibians (e.g., frogs, toads, and salamanders) and reptiles (e.g., snakes, turtles, and terrapins)] e xhibit 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 bu ffers during adult life st ages (Bried and Ervin 2006), indicating the unique nature of riparian fore sts as foraging habitat for rare, threatened and endangered bats (Lookingbill et al. 2010).

Many riparian areas in wester n Maryland are currently forest ed (e.g., 75.8% of the land area within 300 ft of streams is forest). Any de nuded 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 ha rm 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 (Tab le 5-2). The distance is also cons istent 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)Recom m

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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 c onservation 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 includi ng the guidance of compatible land uses and land management practices. These data represent the most up-to-date unders tanding 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 nu mbers of rare species an d habitat. Thus, BioNet considers areas with: (1) only known occurrences of species a nd habitats; (2) globally rare species and habitats; (3) state ra re species and habitats; (4) anim als of greatest conservation need; (5) watch list plants and indicators of high quality habitats; (6) an imal assemblages (e.g., colonial nesting waterbirds, forest interior species); (7) hotspots for rare species and habitats; (8) intact watersheds; and (9) wildlife corri dors and concentration areas. These areas are prioritized into a five-tiered system:

• Tier I – area is crit ically significant for bi odiversity conservation

• Tier II – area is extremely signi ficant for biodiversity conservation

• Tier III – area is highly signifi cant for biodiversity conservation

• Tier IV – area is moderately signifi cant for biodiversity conservation

• Tier V – area is significan t for biodiversity conservation

Areas identified include those th at 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 designa ted as “irreplaceable natural areas” 8

. Consistent with Pennsylvania st ate forest policy, we recommend a no-disturbance setback within and 600 ft around any priority cons ervation area (Figure 5-4). Prio rity conservation areas should be defined using the best available science and designed so that no irrepl aceable areas of unique habitat could be impacted by MSGD. Portions of the BioNet dataset, sp ecifically irreplaceable natural areas (BioNet Tier I and II sites) and wild lands should initially be considered as priority conservation areas and receive th e recommended 600 ft setback. Bi oNet data products should be kept up to date and publically available, so th at potential MSGD operators have the information required to identify lands for their activities th at would have the leas t impact on the natural resources of Maryland. The methods used to gene rate BioNet products should be published in the scientific literature.

Caves were addressed in Chap ter 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 sp ecial 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 enda ngered species in danger of extinction throughout significant po rtions 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 Jonathan McKnight (DNR - Wildlife and Heritage Serv ice, Associate Director Natural Heritage Program),

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### E. Noise and light Noise and light pollution associat ed with unconventional gas devel opment have not been studied in depth, but increasing evidence suggests that th ese factors have signif icant effects on wild animals (Beier 2005, Pijanowski et al. 2011). More research on the topic is needed, particularly with respect to noise. Noise pollu tion can affect wildlife in at least two ways: (1) disruption of communication by masking acoustic si gnals (primarily an issue for birds, but may also affect amphibians and terrestrial mammals); and (2) re ductions in abundance, di stribution 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 fr om 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 leks 13 (Blickley et al. 2012). This sound pre ssure level is similar to what is measured 1300 ft from drilling rigs and main acce ss 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 (F rancis 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 rate s at levels close to those expected in a landscape without compressor nois e (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 a nd 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 engi nes with appropriate mu fflers; 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 sp ecies and circumstances, can lead to changes in survival and fecundity (e.g., Beier 2005). Bats, for example, us e their limited vision to exploit low levels of light as they leave a roost and to avoid obstacles [such as the capt ure nets used by biologists that study bats (Wang et al. 2004)]. No tably, bats are known to avoid di sorienting bright light. Bats are farsighted, suggesting they us e light more often when it is fu rther away and dim, and switch to echolocation for objects that are closer. When migrating, bats will use vision rather than echolocation, which helps to expl ain why they are known to fly into wind turbines (Johnson et al. 2003). With song birds, artificial lighting has b een shown to shift singi ng to earlier morning hours, alter mating success, and result in an ear lier start of egg layi ng in spring (Miller 2006, Kempenaers et al. 2010). Artificial lighting alters foraging, reproduc tive, 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 Ma rcellus Shale Gas Development in Maryland

5-11 behaviors in amphibian species (Andrews et al. 2008). For exampl e, frog calls are reduced under artificial lighting, which can reduce mating succe ss and thus affect population dynamics (Baker and Richardson 2006). Artificial ligh ting near aquatic habitat can also become an attractive nuisance, attracting insects that subse quently die before finding new habitat.
There are two sources of light that are commonly found at dr ill pad sites during MSGD: (1) artificial lighting, used to illumina te the site or transportation rout es to and from, or between drill pad sites, and (2) flaring of unwanted or wast e gas during well completion. Although the impact of artificial light in rural settings such as we stern Maryland is fairly well documented, relatively little has been recommended as BMPs by the vari ous states for unconventional gas development. Some states have suggested fl aring 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 anti cipated, but this requir ement only pertains to Dark Sky Areas. The Forest Distri ct Manager is required to coordi nate with drilling operators to reduce conflicts during special events on state lands that require dark skies (PADCNR 2011). Proposed rules in Colorado and BMPs recommen ded by API also mention light pollution (API 2011), but only suggest consid ering light as a motivation for increasing setbacks from residences. Proposed rules in New York are the mo st protective of wild life, requiring lighting used at well pads to shine downward during bi rd migration periods (A pril 1–June 1 and August 15–October 15)(NYSDEC 2011).
Additional best management practices available to Maryland include re quiring: (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 polluti on 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 signif icant effects on even a largely forested landscape such as western Maryla nd. 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). Th ese impacts include: mortality from road construction, mortality from collision with vehicles, modification of animal behavior, alteration of the physical environment, alteration of the ch emical 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 lit tle activity (Gibbs and Shriver 2005) and by genetic isolat ion of species with poor dispersa l abilities (Kelle r et al. 2004). These studies illustrate the importance to terrestrial wildlife of minimizing new infrastructure development in lands that are currently relativ ely undisturbed. The potential impacts of road noise have been discussed above, and the cons equences of increased impervious surface on aquatic resources are addressed in Chapter 6 of this report.

A relatively sparse network of roads currently fragments the Ma rcellus Shale region of western Maryland, which translates to si gnificantly lower cumulative eco logical risk than the much denser road network of the eastern part of the st ate. 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 (Fi gure 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 ro ads and pipelines can be anticipated with MSGD. A study of the landscape changes due to na tural gas extraction in the Marcellus shale region of Pennsylvania found an increase in forestedge of 380 miles in Bradford County and 721 miles in Washington County between 2004 and 2010, w ith 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 thr ough 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 protec tive if all setbacks described in this chapter be applied to road construction as well as well-pad developmen t: 300 ft from riparian areas, 600 ft from irreplaceable natural areas and wildlands, and 1,000 ft from caves. All new infrastructureRecom m

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. Additional BMPs advocated by Pennsy lvania DCNR include (PADCNR 2011):

• A pre-construction inventory should be performed within the anticipated areas of disturbance to determine the appropriate prevention methods, p redict control needs and assess its level of responsibility for management.

• Soil disturbance should be minimized to decrea se introduction. Consider co-location within previously disturbed areas and/or alternative construction methods.

• The operator should clean equipment in an appropria te 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 t hat reproduce prolifically from rhizome/root segments prior to disturbance. Pre-treatmen t may limit the spread of the invasive plant infestations upon completion of disturbance activities.

• Disturbed areas should be surveyed annually at th e appropriate time of year to detect early infestations.

• Management and control of post-disturbance infestati ons 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 reclam ation 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) pos t-activity restoration to pre-treatment community structure and composition using seed that is certified free of noxious weeds.



### H. Reclamation
Reclamation and site decommissi oning 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 sp ecies and minimizing opportunities for non-native plant invasions. Consistent with our recommenda tions in Chapter 4, reclamation planning should be conducted in two separate phases. Within an established peri od of time following the construction and drilling phases of development and bringing a well into pr oduction, any portion of a we ll pad site that is not needed for gas production should be reve getated. New York and Pennsylvania provide specific recommendations for this interim pha se including creating soft edges around new clearings by maintaining current understory sh rubbery or planting native plants (NYSDEC 2011); revegetation should avoid wet seasons an d wet periods outside of wet seasons to minimize impacts on soils, water, and vegeta tion (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 fo rest 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 infrastructu re, restore the disturbed soil, re -contour the site, and provide

15 Ibid.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

5-15 a permanent vegetative cover. Clea r objectives for final site rest oration 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 th e country is forest cover. In all cases, species planted should be in their na tural geographic range and local stock should be preferred (PADCNR 2011).



### I. Key recommendations
5-A Minimize well pad size, cluster multiple well pa ds, and drill multiple wells from each pad to minimize the overall extent of disturban ce 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 a nd/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 el sewhere in the region.

5-A.3 Implement comprehensive planning proce ss 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 w ith 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 a ll floodplains, wetlands, seeps, vernal pools, streams, or other surface water bodies.

5-C.2 Exclude all development activities from prio rity conservation areas (BioNet Tier I and Tier II sites and wildlands). Enfo rce a 600 ft setback from these areas.

5-C.3 Enforce 1,000 ft setback from any cave to re duce stress to bats and other obligate subterranean species.

5-D Review local noise ordinances to ensure th ey 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 dril ling operations during sens itive migratory and mating

seasons.
5-E Reduce the amount of light pollution at drill pa d sites by restricting night lighting to only when necessary and to only the amount of lighting required, dire ct light downward, instead of horizontally, use fixt ures that control light direc tionality 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 restri ctions 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 applicati on for preventing the introduction of invasive speci es and controlling any invasi ve 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 dr illing to reduce opportunitie s for invasion and (2) postactivity restoration using species native to the geographic rang e and seed that is certified free of noxious weeds.



### J. Literature cited Alkemade, R. M., M. van Oorschot, L. Miles, C. Nelleman, M. Bakkenes, and B. ten Brink. 2009. GLOBIO3: a framework to investigate options for reducing global terrestrial biodiversity loss. Ecosystems 12 :374-390. Andrews, K. M., J. W. Gibbons, and D. M. Jochimsen. 2008. Ecological Effects of Roads on Amphibians and Reptiles: A Literature Review. Herpetological Conservation 3 :121-143. API. 2011. Practices for Mitigating Surface Impacts A ssociated with Hydraulic Fracturing. API Guidance Document HF3. American Petroleum Institute, Washington, DC. Baker, B. J., and J. M. L. Richardson. 2006. Th e effect of artificial light on male breeding-season behaviour in green frogs, Rana clamitans me lanota. Canadian Journal of Zoology-Revue Canadienne De Zoologie 84 :1528-1532. Barber, J. R., K. R. Crooks, and K. M. Fristrup. 2009. The costs of chronic noise exposure for terrestrial organisms. Trends in Ecology & Evolution 25 :180-189. Bearer, S., E. Nicholas, T. Gagnolet, M. DePhilip, T. Moberg, and N. Johnson. in press. Evaluating the scientific support of conservation best management practices for shale gas extraction in the Appalachian basin. Environmental Reviews. Beier, P. 2005. Effects of Artifical Night Lighting on Terrestrial Mammals. Pages 19-42 in C. Rich and T. Longcore, editors. Ecological consequences of artif icial night lighting. Island Press, Covelo, CA. Bentrup, G. 2008. Conservation buffers: design gui dlines for buffers, corridors, and greenways. Gen. Tech. Rep. SRS-109. Department of Agriculture, Forest Service, Southern Research Station, Asheville, NC. Blickley, J. L., D. Blackwood, and G. L. Patricelli. 2012. Experimental evidence for the effects of chronic anthropogenic noise on abundance of greater sage-grouse at leks. Conservation biology 26 :461- 471. Bodie, J. R. 2001. Stream and riparian management for freshwater turtles. Journal of Environmental Management 62 :443-455.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

5-17 Boicourt, K., and Z. P. Johnson, editors. 2010. Comprehensive strategy for reducing maryland's vulnerability to climate change. University of Maryland Center for Environmental Science and Maryland Department of Natural Resour ces, Cambridge, MD and Annapolis, MD. Burke, V. J., and J. W. Gibbons. 1995. Terrestrial Buffer Zones and Wetland Conservation: A Case Study of Freshwater Turtles in a Carolina Bay. Conservation Biology 9 :1365-1369. Castelle, A. J., A. W. Johnson, and C. Conolly. 199 4. Wetland and Stream Buffer Size Requirements - A Review. Journal of Environmental Quality 23 :878-882. Crawford, J. A., and R. D. Semlitsch. 2007. Estimation of Core Terrestrial Habitat for Stream-Breeding Salamanders and Delineation of Riparian Buffers for Protection of Biodiversity. Conservation Biology 21 :152-158. Drohan, P. J., M. Brittingham, J. Bishop, and K. Yoder. 2012. Early trends in la ndcover change and forest fragmentation due to shale-gas development in Pennsylvania: A potential outcome for the northcentral Appalachians. Environmental Assessment 49 :1061-1075. Francis, C. D., J. Paritsis, C. P. Ortega, and A. Cruz. 2010. Landscape patterns of avian habitat use and nest success are affected by chronic gas well compressor noise. Landscape Ecology 26 :1269- 1280. Franz, R., and D. Slifer. 1971. Caves of Maryland. Educational Series No. 3. Maryland Geological Survey. Frick, W. F., J. F. Pollock, A. C. Hicks, K. E. Langwig, D. S. Reynolds, G. G. Turner, C. M. Butchkoski, and T. H. Kunz. 2010. An emerging disease cause s regional population collapse of a common North American bat species. Science 329 :679-682. Fure, A. 2006. Bats and lighting. The London Naturalist 85

. Gibbs, J. P., and W. G. Shriver. 2005. Can road mortality limit populations of pool-breeding amphibians? Wetlands Ecology and Management 13 :281-289. Grant, E. H. C., J. D. Nichols, W. H. Lowe, and W. F. Fagan. 2010. Use of multiple dispersal pathways facilitates amphibian persistence in stream netw orks. Proceedings of the National Academy of Sciences of the United States of America 107 :6936-6940. Harper, K. A., S. E. Macdonald, P. J. Burton, C. Jiquan, K. D. Brosofske, S. C. Saunders, E. N. S. Euskirchen, D. A. R. Roberts, M. S. Jaiteh, and P.-A. Esseen. 2005. Edge Influence on Forest Structure and Composition in Fragmented Landscapes. Conservation Biology 19 :768-782. Harris, L. D. 1984. The fragmented forest. University of Chicago Press, Chicago, USA. Hodges, M. F., Jr., and D. G. Krementz. 1996. Neotropical Migratory Breeding Bird Communities in Riparian Forests of Different Widths along th e Altamaha River, Georgia. The Wilson Bulletin 108 :496-506. Johnson, G. D., W. P. Erickson, M. D. Strickland, M. F. Shepherd, D. A. Shepherd, and S. A. Sarappo. 2003. Mortality of bats at a large-scale wind po wer development at Buffalo Ridge, Minnesota. American Midland Naturalist 150 :332-342. Keller, I., W. Nentwig, and C. R. Largiader. 2004. Recent habitat fragmentation due to roads can lead to significant genetic differentiation in an abunda nt flightless ground beetle. Molecular Ecology 13 :2983-2994. Kempenaers, B., P. Borgstroem, P. Loes, E. Schlicht, and M. Valcu. 2010. Artificial Night Lighting Affects Dawn Song, Extra-Pair Siring Success, and Lay Date in Songbirds. Current Biology 20 :1735-1739. Lookingbill, T. R., A. J. Elmore, K. A. M. Engelhardt , J. B. Churchill, J. E. Gates, and J. B. Johnson. 2010. Influence of wetland netw orks on bat activity in mixed-use landscapes. Biological Conservation 143 :974-983. McComb, W. C., K. McGarigal, and R. G. Ant hony. 1993. Small mammal and amphibian abundance in streamside and upslope habitats of mature Douglas-fir stands, western Oregon. S Northwest Scientist 67

. Miller, M. W. 2006. Apparent effects of light pollution on singing behavior of American robins. Condor 108 :130-139.K.N. Eshleman & A.J. Elmore (2013) Chapter 5

5-18 Moore, R. D., D. L. Spittlehouse, and A. Story. 200 5. Riparian microclimate and stream temperature response to forest harvesting: A review. Journal of the American Water Resources Association 41 :813-834. NYSDEC. 2011. Revised draft supplemental generic envi ronmental 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. 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. Patricelli, G. L., and J. L. Blickley. 2006. Avian communication in urban noise: Causes and consequences of vocal adjustment. Auk 123 :639-649. Perry, R. W., T. B. Wigley, M. A. Melchiors, R. E. Thill, P. A. Tappe, and D. A. Miller. 2011. Width of riparian buffer and structure of adjacent plantati ons influence occupancy of conservation priority birds. Biodiversity Conservation 20 :625-642. Pijanowski, B. C., L. J. Villanueva-Rivera, S. Dumyahn, A. Farina, B. L. Krause, B. M. Napoletano, S. H. Gage, and H. Pieretti. 2011. Soundscape ecolo gy: The science of sound in the landscape. BioScience 61 :203-216. Poot, H., B. J. Ens, H. D. Vries, M. A. H. Donners , M. R. Wernand, and J. M. Marquenie. 2008. Green Light for Nocturnally Migrating Birds. Ecology and Society 13 :14. Riitters, K. H., and J. D. Wickham. 2003. How far to the nearest road? Frontiers in Ecology and Environment 1 :125-129. Ritters, K. H., and J. D. Wickham. 2012. Decline of forest interior conditions in the conterminous United States. Scientific Reports 2 :1-4. Semlitsch, R. D. 1998. Biological Delineation of Terrestrial Buffer Zones for Pond-Breeding Salamanders. Conservation Biology 12 :1113-1119. Semlitsch, R. D., and J. R. Bodie. 2003. Biol ogical Criteria for Buffer Zones around Wetlands and Riparian Habitats for Amphibians and Reptiles. Conservation Biology 17 :1219. Slonecker, E. T., L. E. Milheim, C. M. Roig-Silva, A. R. Maliza, D. A. Marr, and G. B. Fisher. 2012. Landscape consequences of natural gas extrac tion in Bradford and Washington Counties, Pennsylvania, 2004-2010. U. S. Geological Survey, Open-File Report 2012-1154. Strong, K. 2008. Conserving natural areas and wildlif e in your community: smart growth strategies for protecting the biological diversity of New Yo rk's Hudson River Valley. New York Cooperative Fish and Wildlife Research Unit, Cornell University, and New York State Department of Environmental Conservation, Hudson River Estuary Program, Ithaca, NY. Thompson, H. 2012. Fracking boom spurs environmental audit. Nature 485 :556-557. Trombulak, S. C., and C. A. Frissell. 2000. Review of Ecological Effects of Roads on Terrestrial and Aquatic Communities. Conservation Biology 14 :18-30. Wang, D., T. Oakly, J. Mower, L. Shimmin, S. Yim, R. Huoneycutt, H. Tsao, and W.-h. Li. 2004. Molecular evolution of bat color vision genes. Molecular Biology and Evolution 21 :295-302. Wanger, S. 1999. A review of the scientific literature on riparian buffer width, extent and vegetation. Office of Public Service & Outreach Institute of Ecology, University of Georgia. Wiltschko, W., U. Munro, H. Ford, and R. Wiltschko. 1993. Red light disrupts magnetic orientation of migratory birds. Nature 364 :535-537.Recom m



### Appen d ended Best



### ix 5A Mana g eme nt Practice s for Marcel l

5-19 l us Shale G a s Develop m ent in Mar y landK.N. Eshl e man & A.J. E lmore (201 3 )

5-20 C h apter 5Recom m ended Best Mana g eme nt Practice s for Marcel l

5-21 l us Shale G a s Develop m ent in Mar y landK.N. Eshl e man & A.J. E lmore (201 3 )

5-22 C h apter 5Recom m ended Best Mana g eme nt Practice s for Marcel l

5-23 l us Shale G a s Develop m ent in Mar y landK.N. Eshl e man & A.J. E lmore (201 3 )

5-24 C h apter 5Recom m ended Best Mana g eme nt Practice s for Marcel l

5-25 l us Shale G a s Develop m ent in Mar y landK.N. Eshl e

(Hodges and et al. 2011), ( 1993) e man & A.J. E

Krementz 1996), ( ( Roe and Georges lmore (201

Bried and Ervin 2 2007), (Semlitsch 3 )

006), (Burke and 1998), (Semlitsc h

5-26 Gibbons 1995), ( C and Bodie 2003) rawford and Se m , (Wanger 1999), ( litsch 2007), (Ga m (Castelle et al. 19 9 C h

ble et al. 2006), 4), (McComb et a h apter 5

(Perry l.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

6-1 

### 6. Protecting aquatic habitat, wildlife, and biodiversity 1
Freshwater aquatic habitats (defin ed as all streams, rivers, seep s, springs, wetlands, lakes, ponds, reservoirs, and floodplains) are un ique 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, Lo we 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 e nvironment through stream dewatering, runoff generation, non-poi nt and point source pollution, el evated thermal regimes, and indirect impacts through ripari an habitat degradation. In Chap ter 4 we discussed the possible adverse impacts of temporary stream dewate ring 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 sp ecies that contribute to Maryland’s biotic diversity and recreational opport unities (e.g., trout). Land surface and channel erosion can greatly increase suspended sediment concentrations and turbidity levels—part icularly during runoff events—resulting in decreases in water clarity and increased sedi mentation 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 vegeta tion disturbances, or the inadvertent discharge of previously impounded water into streams could negatively affect hab itat quality and impose additional stresses on trout and othe r 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 understandi ng population dynamics and ecosystem f unction (Rice et al. 2001, Rice et al. 2006). Organisms certainly vary in their susceptibili ty 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, Bilto n 2001). Human alteration of land cover proximate to and between aquatic habitat has the potential to adve rsely 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 ha bitat and wildlife, Mary land should consider the larger landscape context of aquatic habitat. This should include considering: (1) how habitat is connected through physical transpor t 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/km 2 (stream length divided by watershed area) in the west to nearly 4.0 km/km 2 in the east (Julian et al. 2012, Elmo re 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 trout 2 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 lands cape. Maryland DNR as part of their Maryland Biological Stream Survey measures stream community composition annually 4 . Recent work to synt hesize these data has advanced in many areas resulting in detailed maps (ins et) delineating classes of stream reaches with similar community composition (represented by different colors in the map) 5

. During Marcellus shale gas development, BMPs c ould be employed that reduce non-point source pollution, maintain habitat of sufficient quality fo r rare, threatened, and en dangered species as well as for species of significant commercial or re creational 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 de tailed stream survey work (MDNR 2010) and synthetic analyses aimed at esta blishing robust descriptions of bot h reference and impacted aquatic populations (Utz et al. 2009). There are many important consid erations 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 (J ulian 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. Retr ieved from http://www.dnr.st ate.md.us/streams/MBSS.asp
5 Unpublished model results, Matthew Fitzpa trick, UMCES, Appalachian Laboratory.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

6-3 provide a detailed spatial represen tation 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 hab itat 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 BM Ps have been developed that cover activities in both upland and riparian environmen ts. To best protect aquatic, we tland, 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 ri parian buffer or, where forest is not present, a minimum setback distance from aquatic habitat. Upland forest buffers provide benefits to a quatic environments that can be classified as chemical, physical, or bi ological. The scientific basis for imposing a buffer with a specific width depends on the overall ratio nale for the buffer. Many favorable chemical and physical characteristics (e.g., stream nitrate concentration, sediment concentration, water temperature, benthic light availabi lity) can be achieved by imposing a relatively small forest buffer that might not be much wider than the averag e canopy height (~100 ft). Consequently, a broad array of literature that focuses on aquatic habi tat condition and biological diversity supports the adoption of a 100 ft buffer from aquatic habitat (see Wanger 1999 a nd references therein). Wider buffers are required to protect herp tiles (reptiles and amphibians) th at use forest riparian buffers (particularly on floodplains) for forage or dispersal. Therefore, the mo st 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 pr esent in the proposed setback.

Where forest riparian buffers are not present, eith er 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 fr om aquatic habitat in ag ricultural 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 befo re it enters aquatic habitat. Similarly, in urban settings setbacks provide n eeded space for stormwater management, including retention and diversion of stormwater, thus reducing the ch ance that any spills and leaks would lead to contamination of aquatic ha bitat (see Chapter 4). Finally, in a ll settings (forest, agricultural, and urban), setbacks from aquatic habitat provi de benefits to recr eational resources. Many streams, some located close to urban and suburba n communities, are used frequently for birding, fishing, boating, and swimming. To maintain the quali ty 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 fore sted (i.e., a riparian forest buffer) and Maryland should use MSGD as an impetus to continue it’s overa ll efforts to increase th e 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 th e 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 ha bitat for shale gas development should be permitted in Maryland. We specifically defi ne direct disturbance as any site preparation, earth-moving, well pad construction, grading, well drilling, equipment storage, or other development activity on the land surface a nywhere aquatic habitat is present ( exceptions would be disturbances associated with any necessary acces s road, utility and pipelin e corridor construction activities that are specifically addr essed 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 habita t). Because setbacks are intended in part to reduce the chance that spills of cont aminated 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 agricultu ral settings). In all cases the in tent is to protect the aquatic habitat, therefore while slope, la nd-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-disturban ce buffer for situations where a body of water contains threatened or endangered species or is considered either a hi gh quality or exceptional value stream or body of water 6 . Similarly, West Virginia also enforces a 300 ft buffer for development near streams with na turally reproduci ng trout populations 7

. 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 rese rves 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 floodplains 8 , which we do not

6 However, PADEP enforces a 150 ft buffer for high qualit y 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_Stat us/bills_text.cfm?billdoc=hb401%20enr.htm&yr=2011&sesstype=4X&i=401.
8 Floodplains can be adequately described by FEMA floodpl ain 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 fl oodplain (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 slop e 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 Ma rcellus 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, co mbined with the fact that most of the area within 300 ft of streams is forested (and no-net-lo ss of forest is recommended), suggests that there are multiple interacting characteri stics 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 Inventory 9 (NWI) and by additional mapping efforts conducted by the Maryland DNR 10 . Total wetland area as defined by the union of these data sets is 20,000 acres, 7000 acres of whic h is made up of small wetlands with an area less than 10 acres. Certain wetlands with rare, threatened, endangered species or unique habita t 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 additio nal 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 ot her states to provide additional protection of high-va lue or highly sensitive assets such as 100-year floodplains, wetlands, high quality streams, natural trout stream s, 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 developm ent undertake efforts to identify critical areas with known endangered species, unique habitats , significant migration and breeding areas for birds, mammals and aquatic organisms, and si gnificant 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.aspK.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 se lection, thus reducing the chance of selecting sites th at turn out to be unsuitable or unfeasible for MSGD. Pennsyl vania has already developed a Pennsylvania Natural Diversity Inventory (PNDI) and associated Environmental Review Tool (ERT) that allows the public, a consultant, property ow ner, or project planner to perf orm 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 Co unty Natural Heritage Inventory (CNHI) effort in Pennsylvania is another example of a coopera tive program undertaken by the Pennsylvania Natural Heritage Program (PNHP) partnership. The CNHI performs systematic studies of critical biological resources of the stat e 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 dr illing application or comprehensive drilling plan for review and approval, a prospective shale gas de veloper 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 activi ties 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 considerab le progress in this ar ea 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 importa nt 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 ensu re the persistence of imperiled fauna 11 . When documented properly, such data could be eff ectively used to channel MSGD into watersheds or sites within watersheds where it will have the least im pact on aquatic habitat and biodiversity.

The use of “stronghold watersheds” implicitly assu mes that aquatic biodiversity conservation should take a “watershed approach” since some pa rticularly sensitive species may cease to persist if even relatively small portions of these wate rsheds 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 distri buted throughout the central Appalachians, including western Maryland. Brook trout are se nsitive 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 populat ions, with sensitivity to agriculture west of the Blue Ridge in Maryland (Utz et al. 2010) a nd near universal extirpation from watersheds exceeding 4% impervious surfaces (Stranko et al. 2008). Brook trout are now dramatically reduced throughout their histor ic range (Hudy et al. 2008). Al though 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.aspRecommended Best Management Practices for Ma rcellus 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 pr esent at low abundances. Thus, many of the existing populations do not ha ve sufficient space or numbers for long term viability (Hilderbrand and Kershner 2000, Hilder brand 2003) and many existing populations will likely be extirpated within 20 years if the prev ious 20 years is a guide (Stranko et al. 2008)). Activities that decrease abundan ce or fragment existing popula tions will further increase extirpation risk in even the stronghold watersheds.

Our research into BMPs proposed or in use to prot ect aquatic habitat in ot her states suggest that stream setbacks represent the primary instru ment 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). Therefor e, some states have included language attempting to address cumulative impacts in other ways. For example, in Colorado the responsib ility is put on drilling operators to minimize land disturbance, consolid ate 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 centr alization of infrastructure, us e of specialized BMPs, well pad spacing and density adjustments, working with ot her 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 plan ning, 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 watersheds 12 , Maryland should consider nove l ways of establishing areal limits on surface development of all kinds (e.g., residential, commercial, wind power, unconventional shale gas, etc.) to address cumulati ve impacts. There is substantial scientific evidence that aquatic habitat and biodiversity respond to cumulative land disturbances or land use changes (e.g., urbanization), eith er linearly or non-linearly (B ooth et al. 2002, Walsh et al. 2005, Petty et al. 2010, Merriam et al. 2011). While es tablishing 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 c over (Utz et al. 2009). Am ong 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 excel lent candidates for such additional protections, but also possibly many or all of the watershe ds 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 regula tory authority (see Chapter 4).K.N. Eshl e

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6-9 

### C. Design and construction of well pads, access roads, pits, ut ility corridors, and pipelines Implementation of BMPs in design and constructi on 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 a quatic biodiversity. In additi on to utilizing appropriate nodisturbance setbacks to protect a quatic habitat, proper implementa tion of appropriate erosion and sediment control measures (see Chapter 4) a nd stormwater pollution prevention techniques are important ways that aquatic habitat can be conserved.

Well pads. We have recommended “zero-discharge” we ll 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 an d active collection, treatment, and di sposal of stormwater runoff has ceased. During well drilling when well pads are be ing 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 whic h stormwater can be actively coll ected 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 complete d (or possibly during periods between individual well drilling events). Under these conditions, an d 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 pollu tants through leaks from produced water storage tanks or liquid lines on-site, or fr om tanker trucks used to transpor t 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 polluta nts 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 quali ty (i.e., suspended solids) and quantity (i.e., peak discharge) issues might be through constr uction 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 pha ses. Regular (annual) maintenance of the pond would also be needed to en sure that the system is functioning correctly at all times. Additional water quality treatment could be obtained through operation of a constructed wetland sited downstrea m of the pond outlet.

As discussed in Chapter 4, these recommendations are at least in partial conflict with two of Maryland’s performance standards fo r controlling stormwater pollution 13 : 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 ra tes shall be maintained by promoting infiltration through the use of stru ctural and non-structural methods. Clearly,

13 Maryland Stormwater Design Ma nual , 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.aspxK.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 probl ems during periods when active stormwater management wo uld not be a viable option.

Access roads. Wherever feasible, use of existing road s 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 inade quate and new roads will be needed. To protect aquatic habitat and minimize associated stormwat er runoff, the design, routing, construction, and maintenance of any access roads to a well pad shoul d be done in a manner that can safely support considerable heavy truck traffic, minimizes the cl earing of forests, avoids steep slopes, avoids wetland and stream crossings, utili zes bridges or arched culverts for all stream crossings (leaving the stream bed relatively undisturbed), and promot es sheet flow runoff from the road surface onto surrounding soils wherever possible. Roads should not be located in or para llel to perennial or intermittent stream channels (i.e., no stream fo rds). Consistent with Pennsylvania DEP proposed rules, all wetland crossings should be avoided. Pennsylvania DCNR desc ribes particularly good practices for constructing and main taining such gravel roads to facilitate Marcellus shale gas development in Pennsylvania state forests that would also be highly ap plicable to western Maryland (PADCNR 2011). For road construc tion, Pennsylvania DCNR: (1) recommends utilizing materials and designs (e .g., crowning, elimination of ditche s, 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 maintain ing sub-base stability (PADCNR 2011). In Pennsylvania (as in western Maryla nd), it is typical for wa ter to be a seasonal problem on dirt and gravel roads a nd one of the best ways to minimi ze the risk of road failures is to selectively schedule hauling ope rations to avoid or minimize tr affic 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 concer ns 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 containmen t 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 vehicula r access to sites, road corridors can also be designed and construc ted to facilitate below-ground tr ansmission of gas, water, and AC power (if desired) to each well pad (as in the case of Pennsylvania stat e 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 genera tors). At Tiadaghton State Forest, for example, it was possible to co-locate such infrastructure within a ~35-foot wide corridor imm ediately adjacent to the access road. Co-location of this ancillary infrastructure along th e road corridor helpsRecommended Best Management Practices for Ma rcellus 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 belowgr ound transmission of gas, water, and AC power should be colocated with road infrastructure to minimize imp acts on aquatic habitat. A quatic habitat crossings, where necessary, should be accomplished with appropr iate 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 su ch 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 substrat e 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. Altern atively, Maryland could ban the pr actice 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. Direct ional boring is a trenchle ss construction technique by which an operator can drill dow n next to a stream, bore horizon tally under a stream, and then bore up to the surface on the other side. The t echnique 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 l east 10 ft below the streambed a nd avoiding drilling through highly fractured substrate. In addition, e fforts should be taken to avoid surface and subsurface spills or leaking of drilling fluids.

Surface impoundments. There are currently no construction st andards for the kind of small (< 15 MG) freshwater impoundments that are being used throughout the st ate to temporarily store water prior to its use for hydraulic fracturing in Pe nnsylvania (Marcellus Shal e Advisory Commission, 2011), although larger impoundments require da m construction and operation permits). The facility that one of us (KNE) visi ted in Tiadaghton State Forest wa s a shallow (3-4 ft deep), lined pond equipped with automated water level monito rs that is capable of being continuouslymonitored from either a remote or centralized o ffice location (Figure 1-4). Adequate freeboard can be maintained by pumping out water as needed, a nd a series of standpipes provide a means of safely refilling the pond from water tankers. A buried pipeline enables transf er 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 th e stream network (i.e., there is not an obvious mechanism other than overflow of the structur e by which non-native species could be introduced into a nearby waterway). At a minimum, planni ng for one of these f acilities should include precautionary measures to identify invasive spec ies at water s ources 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 na tural water body should be prohibited to avoidK.N. Eshleman & A.J. Elmore (2013) Chapter 6

6-12 increasing water temperatures in groundwater fed streams and to avoid inadvert ent non-native introductions.

Surface water intake structures. Intake structures should be de signed to avoid entrainment of aquatic organisms (Lien and Manner 2010) and inva sive species management plans should include procedures for effectively washing intake eq uipment 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 main tain 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 (Kapla n et al. 2008). The direct effects of sediments on fish will vary with the concentr ation of suspended matter, duration and timing of exposure, degree of sediment deposition, particle size distribution and type of sedi ment, 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 photosynthe sis throughout the water column leading to reduced primary productivity and, therefore, reduced forage fo r higher trophic levels; (2) reduced periphyton attachment (a mixture of algae, cyanobacteria, heterotrophic microbes, a nd detritus found in most aquatic habitats) and macrophyte growth, leading to reduced animal and pl ant abundance, species richness, and diversity; and (3) increased sediment deposition a nd the loss of physical habitat (Kemp et al. 2011).

Best management practices for sediment and erosi on 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 head water stream ecosystems specifically, comes from ungraded roads on steep slopes or erodibl e 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 maintain ed driving surface of sufficient aggregate can be built to produce si gnificantly less sediment (Sheridan and Noske 2007). In Chapter 4 and elsewhere in this report we discussed th e 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 ro ad 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 duri ng periods of little rai n, but inadequate during periods of flashy flows typical of mountain str eams (Hedrick et al. 2010). Therefore, using a combination of BMPs and recognizing that addi tional protective measures might be necessary during certain times of the year (primarily late winter and ear ly spring), is itself a BMP for Maryland.Recommended Best Management Practices for Ma rcellus 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 ta ke 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 po tential 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 th e largest fish-kill a ssociated with MSGD in PA and WV (Dunkard Creek), suggesting it is an emergi ng 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 cont aining seeds, roots, or ot her 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 containe rs for disposal. During power washing, wash water (including spray) shou ld not discharge within 100 ft of any stream, existing or proposed wetland, or stormwater co nveyance (e.g., ditch, storm drain, etc.). In no circumstances should water that has been tran sferred between watersheds or moved upstream above confluences be discharged into aquatic ha bitat. 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 habita t for shale gas development should not be permitted.

6-B A minimum 300 ft aquatic habitat setback shoul d 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 biol ogical resources of western Maryland should be developed and made available to MSGD applicants. These da ta should be used to effectively channel development away from high-value biologi cal resources and into industrial zones accessible via existing roads and highways.

6-D The use of multi-well pads to access relatively large (~2 mi 2 ) 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 (i ncluding all well pads, access ro ads, public roads, etc.) could be maintained at less than 2% of th e 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 dril ling pads on which all drilling and hydraulic fracturing fluids, chemicals, a nd liquid wastes are collected a nd stored in steel tanks that provide superior primary containment to hol ding 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 s hould include, at the minimum:

6-H.1 A description of water sources to be used to fill any impoundment, including analysis of any invasive sp ecies 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 fo r 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 recommendati ons could be adopted:

6-J.1 Use materials and designs (e.g., crowning, elimination of ditches, etc.) that encourage sheet flow as the preferred dr ainage 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 (p rimarily 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 A ssociated with Hydraulic Fracturing. API Guidance Document HF3. American Petroleum Institute, Washington, DC.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

6-15 Benda, L., K. Andras, D. Miller, and P. Bigelow. 2004. Confluence effects in rivers: Interactions of basin scale, network geometry, and disturban ce 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. For est 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 clim ate 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 c onstruction 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 Revi ew 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. Conservi ng 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 ra nge 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 gr owth 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. Ch annel 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. Jon es. 2011. The impacts of fine sediment on riverine fish. Hydrological Processes 25 :1800-1821. King, G. E. 2012. Estimating frac risk and improvi ng 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. For estry 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 Marcellu s shale: resources for stakeholders in the Upper Delaware watershed region. Pinchot Institute for Conservation. Likens, G. E., and F. H. Bormann. 1974. Linkages be tween terrestrial and aqua tic 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. 200 5. Moving headwater streams to the head of the class. BioScience 55 :196-197.K.N. Eshleman & A.J. Elmore (2013) Chapter 6

6-16 McCormic, J. H., B. R. Jones, and K. E. Hokanson. 19 72. 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 c onditions 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 proge ny survival. Canadian Journal of Fisheries and Aquatic Sciences 45 :1623-1632. NYSDEC. 2011. Revised draft supplemental generic envi ronmental 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 g as activity on state forest lands. Commonwealth of Pennsylvania Department of Conservation a nd 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. Canadi an 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. Environm entally Sensitive Maintenan ce 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 declin es with land cover and temperature changes in Maryland. North American Journal of Fisheries Management 28 :1223-1232. Sweeney, B. W. 1993. Effects of streamside vegeta tion on macroinvertebrate communities of white clay creek in eastern North America. Proceedings of the Academy of Natural Sciences of Philadelphia 144 :291-340. Tarboton, D. G., and M. E. Baker. 2008. Toward s an algebra for Terrain-Based Flow Analysis. in N. J. Mount, G. L. Harvey, P. Alplin, and G. Priestna ll, editors. Representing, Modeling and Visualizing the Natural Environment: Innovations in GIS. CRC Press, Florida. Urban, M. C., D. K. Skelly, D. Burchsted, W. Pr ice, and S. Lowry. 2006. Stream communities across a rural-urban landscape gradient. Drivers Distrib 12 :337-350. Utz, R. M., R. H. Hilderbrand, and D. M. Boward. 2009. Identifying regional differences in threshold responses of aquatic invertebrates to la nd cover gradients. Ecological Indicators 9 :5 56-567.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

6-17 Utz, R. M., R. H. Hilderbrand, and R. L. Raesly. 201 0. Regional differences in patterns of fish species loss with changing land use. Biological Conservation 143 :688-699. Walsh, C. J., A. H. Roy, J. W. Feminella, P. D. Co ttingham, P. M. Groffman, and R. P. Morgan. 2005. The urban stream syndrome: current knowledge and the search for a cure. Journal of the North American Benthological Society 24 :706-723.Recommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

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### 7. Protecting public safety 1
Modern shale gas development is an industrial activity that in volves 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 consid erable distances on public roads to the drilling sites. Further, like any other out door activities, these dr illing 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 particul ar 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 associ ated on-site infrastructure shoul d be treated like other industrial facilities. The first step in prot ecting public safety from some of the primary hazards associated with industrial facilities is siti ng such facilities as fa r away as possible from homes, businesses, public buildings, or places with high levels of recr eational 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 unde rground drinking water supplies (see Chapter 3). As discussed below, se curity measures such as adequate signage, lighting, fencing and supervision that are appropr iate to other industria l facilities should be required to ensure that shale gas development is conducted in as safe a manner as possible (NYSDEC 2011).



### A. Spill prevention an d emergency response The prevention and containment of spills involving hazardous or toxic chemicals used in the completion process, hydraulic fract uring fluids, or wast ewaters at a well site —or during transit to or from a well site—is a very important compon ent of providing protection of public safety, as well as the surrounding environment. As noted previ ously in Chapters 1 a nd 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 sp ecifically 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) a nd across the operators’ ma ny related facilities (e.g., multiple wells and water impoundments). The proce dures outlined in an ERP are intended to provide for the protection of lives (workers and th e public at large), propert y (both on-site and offsite), and the environment, th rough appropriate advan ce planning, safety trai ning, and coordinated deployment of company and community assets. In addition to addressing spill prevention and clean-up procedures, an ERP woul d also logically include proce dures for protecting the public from fires, explosions, or blow- outs that could occur on a well pad 2 . 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_Stat us/bills_text.cfm?billdoc=hb401%20enr.htm&yr=2011&sesstype=4X&i=401K.N. Eshleman & A.J. Elmore Chapter 7

7-2 plans vary from state to state, documents desc ribing 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 i ndividual with the authority to respond to emergency situations and implement the ERP

• Site name, type, location (including a c opy of 71⁄2 minute USGS map), and operator information

• Emergency notification and re porting (including a lis t of emergency contact numbers for the area in which the well site is located; and appropriate regulator y office), equipment, key personnel, first responders, hospitals, and evacuation plan

• Identification and evaluati on of potential release, fi re and explosion hazards

• Description of release, fire, and explos ion 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, a nd 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 hydr aulic 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 a nd standardized PPC Plan would also include: (1) assigning 9-1-1 addresses to sites to aid in emergency re sponses; (2) providing geographic positioning system (GPS) coordinates for access road s and well pad sites; and (3) distributing PPC Plans to the appropriate county emergency manage ment coordinator so that emergency responders would have immediate access to MSDS informa tion in the event of an actual emergency (Marcellus Shale Adviso ry Commission 2011). Anot her best practice relate d 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 fractur ing, drilling, flaring) (STRONGER 2011).

As is the policy in most states that we revi ewed, an ERP should be developed in Maryland and submitted to the appropriate state regulatory au thority as part of the well permit application process. The ERP could also be part of an overa ll site-specific safety plan developed by an operator to address the full gamut of public safety issues involving su ch topics as site security and off-site transportation of materi als. 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, a ppropriately trained in specifi c well pad emergencies, public safety, and methods isolating and securing an incident site. Each county should have at least one specialized team of emergency re sponders available at all times to respond to an emergency. The emergency responders should leave control of well blow-outs, fire s or contaminant releases to professional, operator-trained expe rts utilizing equipm ent 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 operati ng condition and on-site throughout the drilling and comp leting phases of the operation.Recom m

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7-4 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, dup licate keys to all locks should be provided to the regulatory agency an d to local emergency responders upon request.



### C. Transportation planning Transportation planning is an important considera tion in shale gas develo pment due to the need for moving large quantities of heavy equipment, ch emicals, water, and wastewater either to or from various sites distributed th roughout a particular region. We di scuss transportation planning in Chapter 9 in the context of prot ecting quality of life and aesthetics in predominantly rural western Maryland, but it should be kept in mind that tran sportation 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 si gnificant logistical challenges a ssociated with transporting and storing the tremendous volumes of sand, pipe, water, and other materials that are necessary to drill and complete a Marcellus shale ga s well. According to the Gover nor’s Marcellus Shale Advisory Commission (2011), the maximum dist ance 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 ge t to areas where it can store th e vast quantities of materials required for drilling a well, the be tter the efficiency of the dri lling operation. Railroads, already in place and operational, could provide an alternative system for effectively a nd efficiently receiving, storing, and trans-loading commodities to we ll heads in Pennsylvania and throughout the Marcellus shale region. The railroad s (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 transpor tation, there would still ex ist the need for trucks to move material and equipment from a rail term inal to the well pads (Marcellus Shale Advisory Commission 2011), so the impact of using rail tr ansportation on truck tran sportation may not be that great. Further, while western Maryland is obviously home to a major CSX rail yard at Cumberland, the closest actual ra il terminal to the region is in Hagerstown—60-100 miles away— perhaps too far away for railroads to play a majo r role in staging MSGD operations. The proximity of the Cumberland rail yard to a major intersta te highway (I-68) that bisects western Maryland would seemingly make this an ideal location fo r an MSGD staging area, however. If Maryland decides to move ahead with MSGD, the state mi ght 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 Pennsyl vania through Rail Freight and Rail Transportation Assistance Programs).

With respect to truck transpor tation, there are obvious risks to public safety (injury, death) associated with accidents involving additional tra ffic onto roads and bridges, plus additional risks associated with exposure to spilled hazardous chemi cals, fires, or explosions resulting from such accidents. As recommended for Pennsylvania, we be lieve 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 pr ior 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 a nd structural evaluation ofRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

7-5 locally-owned bridges currently ex empt from federally mandated in spections (typically 8 ft to 20 ft) to ensure that these structur es 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 c ould 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 bri dges) should be upgraded to support such traffic prior to shale gas development occurring or such traffic should not be permitte d 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 es tablishing 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 Commi ssion 2011). The protocol would be similar to how ‘wide loads’ are presentl y transported in the state of Maryland and would thus require cooperation and coor dination with the state police w ho assume primary responsibility for the highway system.



### D. Key recommendations 3-A The first line of defense in protecting public safety is designing MS GD operations in a way that maintains separation between MSGD infras tructure (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 c onstruction (e.g., casing and cementing) should be followed to ensure wellbore inte grity 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 hydrau lic fracturing fluids into groundwater, causing pollution of underground drinking water supplies and to enable rapid detection in the event of migr ation (see Chapters 1 and 4).

3-B MSGD applicants should be required to develo p site-specific, emergency response plans (ERP) that describes in detail how a part icular 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 sta ndard information, including the names and contact information for first re sponders, and location (including GPS coordinates) of MSGD sites.

3-B.2 The ERP must include variations on sta ndard 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 a ll 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 fu rther control access (particularly important during active drilling an d completion phases of an operation).

3-C.3 Duplicate keys to all locks should be provide d to the regulatory agency and to local emergency responders.

3-D Maryland’s Department of Transportation shou ld calculate, evaluate, and address the major impacts of additional truck traffic on the ro ad 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 curre ntly exempt from federally mandated inspections to ensure that these struct ures are capable of safely handling the additional traffic (and loads) associated with MSGD.

3-D.2 The state should establish a protocol to al low for emergency transport of heavy or oversized equipment during off-hour periods (evenings, nights, and weekends).



### E. Literature cited Marcellus Shale Advisory Commission. 2011. [Penns ylvania] Governor's Marcellus Shale Advisory Commission Report. NYSDEC. 2011. Revised Draft Supplemental Generic E nvironmental 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 Ma rcellus Shale Gas Development in Maryland

8-1 

### 8. Protecting cultural, historical, and recreational resources 1
Western Maryland (Allegany and Garrett County) cont ains a plethora of cu ltural, historical and recreational resources. Many types of sites (e.g., national and state hi storic sites, heritage areas, local historic districts, state parks, wildlife mana gement 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 re sources, such as historical land marks or unique natural landscape features (lakes, waterfalls, etc.), draw cons iderable tourism, generating revenue for local communities and the state of Maryland. In 2011, n early $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-rela ted salaries for the two-county area in 2008 3,4

. A decline in the quality or quantity of resources that attract touris m would potentially limit further economic development in this area. Disturbance associated with site preparation work, well drilling activities, truck traffic, and operation of heavy equipmen t—unless successfully avoided or mitigated for—could negatively impact the enjoym ent of natural areas for hunting, fishing, hiking, boating, and other recreational activ ities. Finally, natura l areas might also be impacted through inadvertent introductions of invasi ve species or losses of natura l biological/landscape biodiversity (see Chapters 5 and 6).



### A. Identification of sites Protection of cultural, historical, and recreational resources must be gin with identification of sites that would be adversely affected by Marcellus shale gas development. However, many of these resources (e.g., national and stat e historic properties) are vi rtually 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 na tional registers of historic proper ties, or are included on the state inventory, to ensure that they receive special consideration, prot ecting them from disturbance or impairment. Many state and federal databases exist to provide such information, but the inventoried data are typically not transmitted to us ers 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 th e permit application pro cess (NYSDEC 2011). In western Maryland, there are six li sted items on the National Trust for Historic Preservation, plus 52 sites in Allegany County and 23 sites in Garr ett County listed on the National Register of Historic Properties. 5 Moreover, there are litera lly hundreds of sites in thes e counties that are listed on the state inventory including hi storic properties, local histor ic districts (Cumberland and Frostburg), historic ceme teries and monuments, roadside histor ical 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 Maryla nd 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/publicla nds/pdfs/economicimpactstudy2010.pdf
5 http://www.mht.maryland.gov/nr/NRPickCounty.html.K.N. Eshleman & A.J. Elm ore (2013) Chapter 8

8-2 area (Mountain Maryland Gateway to the West Herita ge Area that includes the towns of Accident, Deer Park, Friendsville, Grantsville, Kitzmille r, 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 Pl anning and other county and local historic preservation offices during the planning and permit application process to en sure that no eligible or existing cultural or historical sites would be potentially disturbe d or impaired by any aspect of shale gas development.

Western Maryland also contains extensive public recreational resource s 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, a nd two state scenic byways. Most of these state and federal recreational resources and impor tant natural areas are reasona bly 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, cove ring 21% of the total land area. Wildlife management areas cover 17,809 acres (2.6%) a nd state parks cover 10,203 acres (1.5%). Confronted with a similar level of diversity in the types of resources th at exist, Pennsylvania DCNR Bureau of Forestry recommends that any constraints mappi ng done by gas drilling companies operating in the Pennsylvania state fore sts should be done in cl ose 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 consul tation with local governments, state park and forest officials, national park managers, and wildlife managers w ho 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 cu ltural and historical re sources, New York State handles proposed oil and gas dril ling 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 fo r private homes (100 ft) and public buildings or areas (150 ft); (3) restriction on times of ope ration (e.g., avoid tourist season, museum hours, whitewater release dates, openi ng 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 BM Ps that have been proposed in New York include: relocation of MSGD infrastr ucture found damaging by local residents or resource managers, use of camouflage or disgui se 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, Pe nnsylvania 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 localRecommended Best Management Practices for Ma rcellus Shale Gas Development in Maryland

8-3 knowledge of cultural sites, recrea tional trails, trailheads, high use areas, viewsheds, vistas, and high aesthetic areas during the pe rmitting process with a goal of avoiding areas of (or providing increased setbacks from) concentrated recreational activity and developed r ecreational sites when permitting gas related infrastructure (PADCNR 2011). In the Pennsylvania state forests, an important criterion in site selec tion for drilling pads is the degr ee to which locations can provide natural vegetative or topographic screening (PADCNR 2011). Additionally, API recommends that setbacks be increased to take into account prev ailing winds and topography; in New York, sites are assessed for their archeologi cal 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 De pt. 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 De pt. 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 Maryla nd Dept. of Natural Resources Allegany Billmeyer Wildlife Management Area Maryla nd Dept. of Natural Resources Allegany Dan’s Mountain Wildlife Management Area Maryland Dept. of Natural Resources Allegany Sideling Hill Wildlife Management Area Mary land Dept. of Natural Resources Allegany Warrior Mountain Wildlife Management Area Ma ryland Dept. of Natural Resources Allegany Mt. Nebo Wildlife Management Area Mary land 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 Maryla nd 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 Bywa y State Highway Administration AlleganyK.N. Eshl e

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8-5 With respect to state forest recreational areas, Pe nnsylvania 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, recrea tional trails, trailheads, high use areas, viewsheds, vistas, and high aesthetic areas during the pe rmitting process with a goal of avoiding areas of (or providing increased setbacks from) concentrated recreational activity and developed r ecreational sites when permitting gas related infrastructure (PADCNR 2011). In the Pennsylvania state forests, an important criterion in site selec tion for drilling pads is the degr ee to which locations can provide natural vegetative or topographic screening (PADCNR 2011). Additionally, API recommends that setbacks be increased to take into account prev ailing winds and topography; in New York, sites are assessed for their archeol ogical 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 w ith cultural, historical and recr eational resources is presumably afforded through good communication between MS GD operators, local governments, and state regulatory and management agencies . Certainly a first step is the identification of the location of cultural and recreational resource s 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 ow ners 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 tran sparency 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 mi ght consider developing a standardized stakeholder process that could be implemented as part of comprehensiv e planning strategy; the goal of such a process would be to engage stake holders and the community in the most effective ways possible, while allowing the perm it review process to be expedited.



### C. Key recommendations 8-A Applicants for drilling permits should be re quired 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 transporta tion routes to and from MSGD facilities).

8-B Regardless of whether or not a proposed ope ration would be located on state or federal land, best practice would require close consulta tion with local governments, state park andK.N. Eshleman & A.J. Elm ore (2013) Chapter 8

8-6 forest officials, national park managers, and wildlife managers who are familiar with the resources that could be impai red by shale gas development.

8-C Applicants should be required to submit a visu al resource mitigation plan as part of the permit application process based on site-speci fic assessment (i.e., viewshed analysis).

8-D Site selection for drilling pads in Maryland should be locatio ns that can provide natural vegetative or topographic screening.

8-E Siting of well pads, or the routing of MSGD-rela ted truck traffic, near high use recreation areas should be a voided if possible.

8-F Maryland should impose a minimum 300 ft setback from all cultural and historical sites, state and federal parks, trails, wildlife mana gement areas, natural areas, wildlands, scenic and wild rivers, and scenic byways to prot ect the region’s most important cultural, historical, recreational, and ecological resources. Setback co nsiderations should include high use areas, noise and visual imp acts, and public safety concerns.

8-G The calculation of setback di stances should consider prev ailing winds, topography, and viewsheds, and repeatable formulas for calculating setbacks shoul d be established.

8-H Mitigative techniques, such as the use of visu al screens, sound barriers, camouflage, and landscaping near cultural and hi storical sites, as well as restricting the times of gas development operations, should be required to minimize disturbances and conflicts with recreational activities in areas adja cent to gas development zones.

8-I Any permitted shale gas development activitie s 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 pr ovide data to help inform peak activity times.



### D. Literature cited Marcellus Shale Advisory Commission. 2011. [Penns ylvania] Governor's Marcellus Shale Advisory Commission Report. NYSDEC. 2011. Revised Draft Supplemental Generic E nvironmental 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 Planni ng 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 values 1
The overall quality of life and aesthetic values in the two west ern Maryland counties derives in large measure from the mostly undeveloped ru ral mountainous landscape dominated by forests interspersed with agricultural lands and relativ ely 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 sl ow-paced way of life, minimal automobile traffic, and associated amenities are attractive features of the area for residents and visitors alike (Wainger and Pri ce 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 pub lic 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, fo rests, wildlife management areas, and wildlands in the region (Boller et al. 2010). While providing economic bene fits to the region, shale gas development in western Maryland clearly has the potential to negatively impact the area’s quality of life and aesthetic ch aracter through altered land use, increased traffic (particularly heavy truck traffic), noise pollu tion, 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 prot ecting 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 deve lopment 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). Simila rly, as discussed in Chapter 8, Pennsylvania DCNR Bureau of Forestry (PA DCNR 2011) manda tes that any permitted shale gas development activities in Pennsylvania state fo rests be timed to avoid periods of peak recreational activity (e.g., holiday weekends, first day of trout seas on, 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 lif e and aesthetic values in western Maryland should include multiple syne rgistic strategies to limit gas-development related disturbance. Similar to best practi ces proposed by New York State and employed by Pennsylvania state forests, Maryland could rest rict 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 visu al screens, and rely on restrictions on hours of operation to mediate the most disruptive activ ities (e.g., during well co mpletion). As discussed in Chapter 1, practices that woul d be generally effective at redu cing conflicts would be: (1) siting well pads away from populated areas (especially those with sc hools 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) siti ng 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 combin ation with such siting criteria, restrictions on hours and times of operation (based on input fr om the public) would likely provide significant additional mitigation of the most problematic conflicts.



### B. Noise control Many studies illustrate a link be tween exposure to noise and ne gative effects on public health. Noise may severely impair quality of life (disrupt sleep, interfere with speech intelligibility), or possibly give rise to both soci al and psychological problems (B odin 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 practi ces to deal with issues of noise control. Colorado has established maximum permissible no ise levels for oil and gas operations at well sites and gas production facilities. In Colorado, operations involvi ng a pipeline or gas facility installation or maintenance, the use of a drilling rig, comp letion rig, workover rig, or well stimulation are all subject to the maximum permi ssible noise levels for i ndustrial zones. In the hours between 7:00 a.m. and the 7:00 p.m., the noi se 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 characteri stics of proposed or ex isting 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) pla cement of walls, artificial sound barriers, or evergreen buffers between sources and recep tors (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 enfo rcement 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 ba rriers where natural noise atte nuation 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 opera tions 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 t ransportation planning Assessing the environmental impact of gas deve lopment 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

2 COGCC Rule 802 Noise AbatementRecom m

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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 (i f feasible and cost effective); and (10) assure adequate off-road parking at well site and delivery areas (API 2011). Further, as propos ed in New York, any deviation from the plan, detours or closures, must be done with advanced public notice. Roaduse agreements should also be established betwee n operators and municipalities to ensure public safety and provide a mechanism for addressi ng road damages attributable to shale gas development in a timely way.

Existing roads should be utilized wherever feasible; if new ro ads are needed, however, potential impacts should be considered along with la ndowner 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 de sign 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 construc tion crews consider using the PA DNCR for construction of permanent non-paved roads to a ddress potential environmental impacts, control erosion, and avoid damage to environmentally sensitive areas (PADCNR 2011).



### D. Visual polluti on/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 facili ties. 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 sh ale 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 cas es, 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 degradatio n of visually-sensitive resources occurs during periods of maximum development activity. We be lieve that removal of major equipment alone would in some cases contribute si gnificantly 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 pr ovide additional benefits (see Chapter 4).

Light pollution has the added pot ential (above and beyond general im pacts to viewsheds) to pose significant direct and indirect effects on the quality of life a nd aesthetic values in western Maryland (Figure 9-2). Indirect e ffects of light pollution were cove red in Chapter 5, and take the form of the different ways in which artificial lighting can infl uence wildlife and biological diversity more generally. Artif icial lighting causes direct eff ects on the quality of life and aesthetic values by being a distraction while dr iving on primary and secondary roads, obscuring dark night skies, and reducing the rural aesthetic qualities of the region. Ma ny visitors to western Maryland frequent campgrounds and other state faciliti es, and expect dark night skies as part of their experience. Maryland could put an empha sis 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 li ghts low and directed down on the work site as much as possible, and increase the use of low-pr essure sodium lights rela tive to other types of lighting. Most polluting are lamps with a strong bl ue emission, like metal halide and white lightemitting diodes (LEDs) (Falchi et al. 2011). Foll owing these guidelines, Maryland could take steps to reduce the amount and natu re (color) of artifi cial lighting used during MSGD. It should also be noted that the light required at differe nt 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 addre ssing security concerns.)



### E. Key recommendations 9-A Well-pad siting should consider the multiple fact ors that influence the quality of life and aesthetics of rural lif e in western Maryland (e.g., locati on 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 Maryla nd should revisit nois e 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 buildingK.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 a void or minimize the greatest conflicts between the public and MSGD.

9-D.3 Require ambient noise level dete rmination prior to operations.

9-D.4 Require construction of arti ficial sound barriers wher e natural noise attenuation would be inadequate.

9-D.5 Equip all motors and engines with appropriate mufflers.

9-E All permit applicants should de velop 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 transporta tion plan should allow for adequate comment by the public, state transpor tation agencies, and county roads departments.

9-F It is recommended that new road cons truction 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 de termine 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 landscap ing 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 as sociated 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 pub lic 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 Peri pheral 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. Internationa l Journal of Tourism Research 13 :496-507. NYSDEC. 2011. Revised Draft Supplemental Generic E nvironmental 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 qua lity 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 Ma rcellus Shale Gas Development in Maryland

10-1 

### 10. Protecting agriculture and grazing 1
After forested land, agricultural land is the second largest contributing land cover in Allegany and Garrett Counties on an areal ba sis, covering 15.6% (108,420 acres) of these two counties. In 2007, the most recent year for which data are publis hed, it is estimated that Allegany County had 302 farms covering a land area of 36,343 acres 2 , while Garrett County had 677 farms covering 95,514

acres. 3 The value of all agricultura l product sales in the two coun ties was estimated as $3.16M and $27.73M, respectively. Farms in these two counties ar e typically small family operations, with the average farm covering 121 acres in A llegany and 141 acres in Garrett County 4 . While many types of county-level data from the Na tional Agricultural Statistics Se rvice are not published to protect economically sensitive information, major crops pr oduced in these two counties include corn for grain, corn for silage, soybeans, winter wheat, ot her hay, barley, and vege tables, in addition to milk, cattle and calves, sheep, hogs, and poultry. In addition to the economic value of crops and other agricultural production, agricu lture also contributes aesthetically to the quality of life and cultural fabric of rural western Ma ryland 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 sa me 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 fert ility soils and cool climat e of western Maryland. Nonetheless, as an important economic activity in the region and as a co mponent of Maryland’s general effort to maintain farming activities throu ghout the state, contributi ng to overall quality of life, we believe that there are some best practi ces 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 ga s-drilling operations (Oswald a nd 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 wast ewater impoundments (which we do not recommend but have been used in PA), and spreading of wast ewater 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 ra nged from neurological to sudden death with the most common effects being reproductive. An imals 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 m ovement 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 charac teristics for producing important agricultural crops. Prime soils have the following inherent characte ristics: 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 relate d qualities: have nearly level to gently sloping to pography, and rarely or never flood during the growing season. 6 Fewer than 2% of western Maryland soils are considered prime soils 7 , and 71% are considered class VI or VII, designating them as suitable for planti ng of permanent pasture, trees, or reserved for wildlife management and recreation 8 . As recommended by Lien and Manner (2010), we agree that soil conditions at sites being c onsidered for shale gas developmen t be evaluated as part of the planning process; prime agricultu ral soils and prime farmland shoul d generally not be disturbed for well pad siting, road construction, or any ancilla ry 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 al ready 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 Maryla nd Department of Agriculture (MDA). Prior to 2007, applications for easements were only accepte d from landowners in de signated Agricultural Preservation Districts. Easement s may be donated or purchased w ith a goal of providing for the perpetual production of local food and fiber. Agri cultural land easements in western Maryland are displayed in Figure 10-1 and compri se 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 minera l 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 th e Grantee’s (i.e., state of Mary land’s) written permission would appear to expressly violate the pr otective 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.htmlRecommended Best Management Practices for Ma rcellus 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 Preservatio n Foundation (MALPF) agricultu ral easements (sometimes located within agricultural districts) protect land from non-agricultural uses and are administered by Maryland Department of Agriculture. Rural Legacy Area Properties ha ve 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 la nd has been protected is Maryland’s Rural Legacy Program, which was enacted by the Ge neral Assembly in 1997, and has dedicated over $210 million to preserve 68,675 acres of valuable farmland, forests, and natural areas throughout the state 10 . 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 greenbe lts of forests and farms around rural communities to preserve their cultural heritage and sense of place, and criti cal habitat for native plant and wildlife species. Relevant to prime farmland, th e Rural Legacy Program also aims to support natural resource economies such as farming, fore stry, tourism and outdoor recreation. Similar to MALPF conservation easements, subsurface activiti es on Rural Legacy properties are prohibited without the Grantees ’ approval and require the Grantee to co nsider 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 overl ays the Accident gas storage dome, and was established by the Maryland Depa rtment 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 undul y compromise the natural and working resources the Area were established to pr otect. In Allegany County, the Mount ain Ridge Rural Legacy Area is delineated around 10,163 acres of existing protec ted lands that may be further connected and

10 http://www.dnr.state.md.us/land/rurallegacy/12thAnniversary.aspK.N. Eshleman & A.J. Elmore Chapter 10

10-4 consolidated, forming a greenway potentially linking ridgetops in West Virginia with Pennsylvania, as well as westwa rd into the Allegheny Plateau.

Protected lands throughout western Maryland have clearly been esta blished with consideration of agriculture and prime soils as an objective. Ther efore, 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 ou r 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 prot ection, 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 deve lopment 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 a nd topsoil separate; (2) remove any drilling muds from fields; (3) avoid soil compaction; and (4) fence in active pasture areas (alternately fence lives tock out of gas development areas).

B. Key recommendations 10-A Soil conditions at sites being c onsidered for shale gas develo pment should be evaluated as part of the planning process.

10-B Prime agricultural soils and prime farm land protected by Maryland’s existing land easement programs should not be disturbed fo r well pad siting, road construction, or any ancillary gas development activities.

10-C Highly erodible soils should also be iden tified as part of the planning process and appropriate best practices em ployed to prevent erosion a nd 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 deve lopment activities, covered during storage, redistributed back onto agricultural land as pa rt of the land reclamation process, and soil compaction should be av oided 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 Marce llus shale: resources for stakeholders in the Upper Delaware watershed region. Pi nchot Institute for Conservation. NYSDEC. 2011. Revised draft supplemental generic environmental impact statement on the oil, gas, and solution mining re gulatory 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 Ma rcellus Shale Gas Development in Maryland

10-5 Thompson, H. 2012. Fracking boom spurs environmental au dit. Nature 485 :556-557.