maryland risk assessment of shale drilling & fracking

DRAFT FOR PUBLIC COMMENT

Assessment of risks from unconventional gas well development

in the Marcellus Shale of Western Maryland

Prepared by:

MARYLAND DEPARTMENT OF THE ENVIRONMENT

MARYLAND DEPARTMENT OF NATURAL RESOURCES

OCTOBER 2014

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Acknowledgements

This comprehensive risk assessment for unconventional gas well development in the Marcellus Shale is the product of a team of devoted scientists and engineers from the Maryland Department of Environment (MDE) and the Maryland Department of Natural Resources (DNR) who volunteered to take on this project in addition to their normal duties. This effort is led by Matthew Rowe, Deputy Director of the Science Services Administration, MDE. The other team members are: from MDE - Farah Abi-Akar, John Backus, Timothy Fox, Anna Kasko, Jed Miller, M.D., Leonard Schugam, and Angel Valdez; and from DNR - Pamela Bush. The assistance of other staff members from both agencies was invaluable and appreciated. We would like to extend a special thank you to Brigid Kenney, Senior Policy Advisor with MDE’s Office of the Secretary and to Christine Conn, Director of the Integrated Policy and Review Unit at DNR for their guidance and direction. We appreciate the assistance of Shareda Holifield of MDE for editing the References. We are especially grateful to Charles Yoe, Ph.D., of Notre Dame University who gave a presentation on risk assessment to the Advisory Commission and generously provided advice on structuring the risk assessment.

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Table of Contents

Acknowledgements ................................................................................................................................................. i

Executive Summary ................................................................................................................................................ 1

Risk Assesment ....................................................................................................................................................... 3

Introduction..................................................................................................................................................... 3

Purpose and Scope .......................................................................................................................................... 3

Methodology ................................................................................................................................................... 4

Risk Assessment for Phases of Unconventional Gas Well Development ........................................................ 7

Phase 2: Drilling ............................................................................................................................................... 8

Phase 3: Hydraulic Fracturing/Completion ..................................................................................................... 9

Phase 4: Production ...................................................................................................................................... 10

Phase 5: Well Abandonment/Reclamation ................................................................................................... 11

Conclusion ..................................................................................................................................................... 12

References ..................................................................................................................................................... 13

Appendix A ...................................................................................................................................................... 1

Risk Ranking: Summary Chart ........................................................................................................................ 1

Appendix B .......................................................................................................................................................... i

Air Emissions ................................................................................................................................................... i

Appendix C ......................................................................................................................................................... 1

Road and Traffic............................................................................................................................................. 1

Appendix D: ....................................................................................................................................................... 1

Drilling Fluid and Cuttings .............................................................................................................................. 1

Appendix E: ........................................................................................................................................................ 1

Fracturing Additives and Fluids .................................................................................................................... 1

Appendix F ......................................................................................................................................................... 1

Noise and Visual Impacts. .............................................................................................................................. 1

Appendix G ........................................................................................................................................................ 1

Water Withdrawal ......................................................................................................................................... 1

Appendix H ........................................................................................................................................................ 1

Wells and Formations .................................................................................................................................... 1

Appendix I .......................................................................................................................................................... 1

Risk Assessment: Waste Disposal ................................................................................................................. 1

Appendix J .......................................................................................................................................................... 1

Acronyms ....................................................................................................................................................... 1

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Executive Summary

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

Drilling Initiative. This initiative will assist State policymakers and regulators in determining whether and how gas production from the Marcellus shale in Maryland can be accomplished without unacceptable risks to public health, safety, the environment and natural resources. The Order requires the Maryland Department of the Environment (MDE) and the Department of Natural Resources (DNR), in consultation with an Advisory Commission made up of a broad array of stakeholders, to undertake studies of natural gas drilling in the Marcellus Shale of Western Maryland.

In January 2014, technical staff from the Departments of Environment and Natural Resources convened to

perform a comprehensive risk assessment for unconventional gas well development (UGWD) in the Marcellus Shale. The Departments identified potential risks related to UGWD, grouped them into like categories, convened technical teams that reviewed scientific literature on risks, evaluated Maryland’s existing regulations and proposed best management practices (BMPs), and developed an overall qualitative risk assessment. Each team evaluated specific risks using consistent assumptions and evaluations of BMP effectiveness.

The risks that were evaluated were grouped into eight categories: air emissions; road damage and traffic;

drilling fluids and cuttings; hydraulic fracturing fluids and potential impacts to surface or ground waters; noise and visual; wells and formations; water withdrawal; and waste. Risks were evaluated in the context of five phases of UGWD: site identification and preparation; drilling; hydraulic fracturing/completion; production; and well abandonment/reclamation. The probability and consequence for each risk was evaluated and, taken together, formed an assessment for each risk of low, moderate or high.

One of the greatest concerns regarding UGWD is the contamination of water supplies, both ground and

surface waters, which may provide sources of drinking water or support ecologically valuable and sensitive aquatic communities. Risks associated with water contamination were rated most commonly as low, and in some cases, moderate, depending on the sensitivity of the receptor. Practices that manage these risks include 1) preventing accidents and spills by managing traffic flow and ensuring a nearly spill-proof pad design, 2) siting the pad far away from sensitive areas, underground hazards, geologic pathways and drinking water sources, 3) requiring stringent casing and cementing standards followed by integrity tests and extensive monitoring to ensure the safest and most leak-proof wells are being developed, and 4) strict standards for transporting and disposing of waste.

Congestion, delays, accidents and road damage caused by the nearly 10,000 one-way truck trips required for

the development of a single well are associated with specific risks ranging across the spectrum of low to high. These estimates rely on data from other states with different intensity and pace of oil and gas development and could not be scaled precisely to Maryland. Road damage is inevitable and necessitates the development of road maintenance agreements prior to initiating UGWD. Plans can be developed to manage traffic flow so that it does not impede important community events and gives citizens more predictability for planning their own transportation needs.

The Comprehensive Gas Development Plan (CGDP) and associated location restrictions and setbacks will be

instrumental in reducing the extent of forested landscape fragmentation and detrimental impacts to terrestrial and aquatic resources. However, the CGDP will not reduce these risks to low and may not have a strong influence

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on the siting of the gas pipelines (gathering lines) that run from the well pad to larger pipelines because the locations of the gathering lines is determined by agreements between private parties, and no governmental approval is needed for the locations of gathering lines. Maryland’s water appropriation program is sufficient to protect sources of drinking water supplies, but there is elevated risk associated with potential harm to aquatic life if large withdrawals occurring over short time periods coincide with drought-, heat- or low flow-stressed water bodies and aquatic communities.

Risks associated with air emissions ranged from low to high and in some instances were not rated due to

insufficient data. Some of the elevated air emission risks and the inability to estimate others result from uncertainty about which specific control technologies would be employed. Many of these risks are associated with the combustion products resulting from truck traffic, on-site engines and compressors. These risks are dependent on the source of fuel used, such as diesel or natural gas, the well pad location and on the extraction intensity. For example, under the 75% extraction scenario, air emissions risks associated with hydraulic fracturing were high.

Risks are inherent in any type of mineral extraction, industrial and construction activity. Across the life-cycle

of the well, from initial site identification to well abandonment and reclamation, UGWD encompasses a broad range of these activities. Maryland draws from its robust stormwater management, soil erosion and control, and water appropriations programs and examines the effectiveness of proposed best management practices for revising its existing gas and oil development regulations. Together, these existing and proposed practices serve to reduce many risks to western Maryland’s citizens, economy and its high quality water, air and natural resources.

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Risk Assesments

Introduction

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

Drilling Initiative. The Initiative will assist State policymakers and regulators in determining whether and how gas production from the Marcellus shale in Maryland can be accomplished without unacceptable risks of adverse impacts to public health, safety, the environment and natural resources. The Initiative is jointly administered by the Maryland Department of the Environment (MDE) and the Maryland Department of Natural Resources (DNR). A key purpose of the Initiative is for MDE and DNR, in consultation with a multi-stakeholder Advisory Commission, to conduct a study that examines a range of considerations related to natural gas exploration and production in the Marcellus Shale. Some Advisory Commission members and public participants suggested that a formal risk assessment for Marcellus Shale gas development would add value to the work performed under this Initiative.

In September 2013, Advisory Commission staff prepared a risk assessment (RA) work plan that identified a set

of risks and was endorsed the Advisory Commission. In January 2014, the Departments convened a technical committee to perform the RA. The technical committee then formed eight focused risk teams composed of subject matter experts in public and environmental health and natural resource management to evaluate groups of similar risks identified in the Advisory Commission’s work plan. Additional risks that were not identified in the work plan but that came to light during risk team evaluations were also considered.

This document describes the RA development and presents its findings. Specifically, it discusses the following:

the purpose and scope of the RA; the methodology which includes the assumptions and development scenarios used to develop the RA; and an overview of risks encountered during each phase of unconventional gas well development (UGWD). The detailed team risk assessments that form the basis for the summary assessment are included as appendices.

Purpose and Scope

The purpose of this RA is to provide a comprehensive risk evaluation for UGWD in the Marcellus Shale in

Western Maryland. Specifically, risks are evaluated through a qualitative assessment of probability and consequence to achieve an overall risk ranking. This RA does not seek to determine a single aggregate risk evaluation for UGWD in Maryland. The RA findings are intended for consideration by the State of Maryland and the Marcellus Shale Advisory Commission to determine if UGWD can be conducted safely in Maryland with current proposed BMPs.

This RA considers several points of reference, or receptors, which could be impacted either directly or

indirectly by UGWD. These are referenced in the report as Human, Community, Ecological, Recreational and other specific receptors. The RA does not consider risks to workers on site or in transit to or from sites where UGWD-related activities are being performed. Additionally, the RA does not consider risks related to downstream infrastructure and processing (such as intrastate or interstate gas lines, downstream processing plants, and liquefaction plants) or risks related to broader national energy policies that affect climate change.

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Methodology

This section describes the methodology and general sequencing used by the Departments to develop the RA.

Work plan and literature review

The Departments initially reviewed the September 2013 work plan drafted by Advisory Commission staff to determine the scope of the RA and the key risks to be considered. The Departments then reviewed risk assessments by Ricardo AEA (Draft Issue 3a, 2014) and King (2012) in order to fully understand the phases of the UGWD process. This review also included the life cycle phase analysis from Eshleman and Elmore’s Recommended Best Management Practices for Marcellus Shale Gas Development in Maryland (2013). Each of these sources was used to determine the UGWD phases evaluated in Section III which were used to conduct the Departments’ RA.

Identification of risks for evaluation

The Departments, in consultation with the Advisory Commission, accepted the 41 risks selected from the September 2013 RA work plan based on a report from Resources for the Future entitled Pathways to Dialogue: What the Experts Say about the Environmental Risks of Shale Gas Development (2013). This list of 41 risks was then subsequently expanded based on further Advisory Commission input and included eight additional risks associated with accidents. These risks were then grouped into the following eight categories:

1. Air emissions 2. Road damage and traffic 3. Drilling fluids and cuttings 4. Hydraulic fracturing fluids and potential impacts to surface or ground waters 5. Noise and visual 6. Wells and formations 7. Water withdrawal 8. Waste Eight technical teams consisting of representatives from the Departments of Environment and Natural

Resources were then convened to develop risk assessments for each category of risk listed above.

Literature and other information sources

The eight technical teams reviewed current scientific literature and other available information to evaluate risks and potential impacts to receptors from UGWD. Each team was responsible for evaluating the risks assigned to their category as well as any additional risks that were identified through team literature and information reviews.

The Departments used information from a range of sources to develop the RA. In addition to the Ricardo AEA

(2013) and King (2012) reports discussed above, the New York State Revised Draft Supplemental Generic Environmental Impact Statement also served as a primary reference. Additional literature and information sources were used to inform development of the individual risk team assessments that form the basis for the summary assessment. Studies that were released during RA development may not have been reviewed due to their timing relative to issuance of this report. It was also clear during literature reviews that many additional studies related to UGWD risks are already planned or underway and will be important for reevaluating risks in any future assessments.

The integrity and credibility of all sources was considered during RA development. Peer-reviewed original

papers published in established scientific journals were considered to be generally credible. Reports from federal, state, or local government agencies were also considered to be generally credible.

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Consideration of best management practices

After scientific literature review, key risks to receptors were identified and then each team evaluated Maryland’s proposed and existing BMPs, including laws, regulations and permits, to determine effectiveness in mitigating risks. The following general principles were used to evaluate BMP implementation effectiveness:

BMPs that require implementation of best available control technology (BAT) that is prescriptive and have proven efficiencies at the start of operation are expected to mitigate risks to a greater degree than BMPs that require plans, time limitations to activities, reporting requirements, or general guidelines.

BMPs that require implementation of a specific BAT should be distinguished from BMPs that provide flexibility for BAT implementation, as the latter is expected to result in site-specific efficiencies that may be difficult to verify and enforce.

The availability, or lack-thereof, of literature or data confirming efficiencies of technology-based BMPs is considered when determining risk mitigation.

BMPs that require documented plans are generally expected to identify measures that avoid or reduce impacts, though they may allow exceptions and require Departmental resources for plan review and compliance measures.

BMPs that require reports or documentation, suggest limits to certain activities, and/or recommend certain measures are generally expected to have limited effectiveness because they are not prescriptive and can be difficult to verify or enforce.

In cases where there was uncertainty whether the existing laws, regulations, permits, and BMPs would be

adequate to protect the respective resources, it was noted in this document.

Development scenarios

Two scenarios developed in consultation with the Departments by Towson University’s Regional Economic Studies Institute were used to determine if risks to receptors were dependent upon different levels of UGWD. Scenarios 1 and 2 assume 25% and 75% extraction levels, respectively, of the available Marcellus natural gas resource in Maryland. Activity scope and duration associated with each different scenario were evaluated during each UGWD phase. Error! Reference source not found. describes the well and well pad development projections for each scenario. It is important to note that these scenarios, while plausible, were constructed specifically to mimic the “boom and bust” cycle that is associated with most mineral extraction operations. The actual pace and intensity of development could differ from the scenarios.

Table 1: Well and Well Pad Development Activity for Scenarios 1 and 2

Item Scenario 1 Scenario 2

Extraction Level 25% 75%

Wells per pad 6 6

Average Wells Drilled/Year 15 45

Total Wells Drilled 150 450

Total Number of Well Pads 25 75

Additional assumptions were based upon information from New York (NY DEC 2011) and information gathered

from UGWD applications submitted to the Departments. (The applications for gas well drilling permits were withdrawn.) These include:

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15-acres of total site disturbance/land clearing per well pad developed (~4 acres for just the well pad).

5,000,000 gallons of water used to hydraulically fracture each well of which 30% (1.5 million gallon) returns as flow back. This information was used to estimate the number of truck trips for delivering freshwater and hauling flowback fluid. This is a conservative assumption as flowback water may be recycled for successive hydraulic fracturing events on a well pad.

Trucks/Equipment: For each well pad, which supports 6 wells, 9,358 one-way trips for heavy trucks and 3,616 one-way trips for light trucks will be required.

Likewise, existing laws, regulations, permits, and BMPs relating to particular risks (water quality, air quality,

noise, waste, etc.) were considered to be protective of, or mitigate risk to, the respective resource/media, when and where appropriate.

Individual risk assessments

In order to ensure comprehensive consideration of potential risks, each team used the UGWD phases described in the next section as the context for evaluating specific activities and corresponding risks. Development scenarios were considered in specific instances when intensity of development had a bearing on the risk level. Each team reviewed current scientific literature on risks associated with activities in each UGWD phase. Current regulations and proposed BMPs were evaluated for their effectiveness in mitigating identified risks.

Based on these criteria and the subject matter expertise of team members, each team performed a qualitative assessment of the probability and consequence for each risk in their assigned category. Probability was categorized as low, medium or high while the consequence was categorized as minor, moderate or serious. Table 2 provides the definitions of the categories. Each risk was then assigned a risk rank (low, moderate or high) based on the combination of the probability that an event would occur and the consequence that the event would have on a specific receptor. Table 3 is the matrix used to determine the risk ranking. In some team reports, additional mitigation measures are identified.

The set of risks identified by the Advisory Commission were considered by the teams and reorganized to the

set of risks provided in Appendix A. This risk assessment chart identifies the specific risk aspect (e.g. traffic, waste disposal), the specific risk agent or chemical (e.g. cost of road damage, drilling mud), the impacted receptor (e.g. community, ecological) and then identifies the risk rank (low, moderate, high) for that particular risk during each phase of UGWD. The next section provides an overview of some of the key risks of concern that were assessed under each UGWD phase.

Table 2: Risk Factors Used

Probability Definition

Low Rarely happens under ordinary conditions; not forecast to be encountered under foreseeable future circumstances in view of current knowledge and existing controls on gas extraction

Medium Occurs occasionally or could potentially occur under foreseeable circumstances if management or regulatory controls fall below best practice standards

High Occurs frequently under ordinary conditions

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Insufficient Data to Determine

Lack of available data to confidently assign probability

Consequence Definition

Minor Slight adverse impact on people or the environment; causes no injury or illness

Moderate Considerable adverse impact on people or the environment; could affect the health of persons in the immediate vicinity; localized or temporary environmental damage

Serious Major adverse impact on people or the environment; could affect the health of persons in a large area; extensive or permanent environmental damage


Lack of available data to confidently assign consequence

Table 3: Risk Ranking Methodology

Risk Rank Low Medium High

Minor Low Low Moderate

Moderate Low Moderate High

Serious Moderate High High

Risk Assessment for Phases of Unconventional Gas Well Development

This section summarizes the key finding from the individual team risk assessments. The full set of risk rankings

can be found in Appendix A while additional details regarding assessment of risk factors and application of proposed and existing BMPs can be found in the team reports that are included as Appendices B through J.

Phase 1: Site Identification and Preparation

Many of the team reports assessed the processes associated with site identification and site preparation separately. These two phases are combined for purposes of streamlining presentation of risks in Appendix A.

Activity/Description:

Prior to conducting any drilling activities in a region, oil and gas companies routinely use seismic assessment surveys to target the best locations for drilling exploratory/production wells. Site preparation involves clearing, leveling, and excavation at a well site to install the well pad, freshwater pits, and any associated access roads.

Probability

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Duration:

Seismic testing: up to 120 days, based upon maximum length of time indicated from a draft permit application in Maryland. Site Preparation: Up to 4 weeks (NY DEC 2011) per multi-well pad

Summary of Risks:

Impacts to communities, people and ecological receptors were low for noise and vibration risks caused by truck traffic and construction activity. Visual impacts from land clearing, pad development and lighting were also ranked low for communities, people and ecological receptors. Contamination of soil, surface or groundwater is generally not a concern during this phase. Risks to people from air emissions were rated as moderate resulting from combustion products and airborne dust from unpaved roads caused by truck traffic. Ecological and farmland impacts associated with clearing land for the construction of new access roads and well pads were rated as moderate due to the likely fragmentation of large blocks of forest, the potential to site well pads on agricultural land and potential stream impacts associated with stream crossings. While the proposed Comprehensive Gas Development Plan and the suite of location restrictions and setbacks will significantly reduce the degree of forest fragmentation and stream impacts, impacts are still expected to occur, but on a localized basis, due to the widespread presence of many sensitive streams and large forested landscapes.

Team Reports:

Appendix B: Air Emissions, Appendix C: Road Damage and Traffic, Appendix F: Noise and Visual

Phase 2: Drilling


After the site has been prepared and the drilling pad installed, one or more drill rigs are brought on site to conduct well drilling. Within Maryland, the Marcellus shale formation is between 5,000 and 9,000 feet below the surface. Drilling entails creating a vertical bore hole until the bit approaches the Marcellus shale, then turning the drill bit and drilling horizontally through the shale for distances that can extend for miles. The hole is then cased and cemented. Typically, three levels of casing (surface, intermediate, and production) are used in a telescoping fashion. The surface casing is run from the land surface to below the deepest freshwater layer. The intermediate casing is run from the surface casing down to the target formation. The production casing is run from the intermediate casing through the target formation and is perforated to allow gas to flow through. All casing strings are cemented in place to stabilize the casing string and also seal the annular space between the casing and borehole to prevent gas or fluid migration between geologic strata.

Duration:

Up to 5 weeks per well (NY DEC 2011).

Summary of Risks:

Impacts to communities, people and ecological receptors were low for noise and vibration risks caused by drilling, casing, cementing activities and other ancillary. Risks associated with increased truck traffic during this phase are anticipated to pose moderate risks to communities and people from noise and vibrations, accidents and damages to vehicles, delays and inconvenience, loss of rural character and other impacts. There is a high risk that costly road repairs will be needed. During the drilling phase, materials (fluids and chemical additives) are brought on to the site, stored (both before and after use), used for drilling and then recycled or transported offsite for appropriate disposal. The high standards set for casing and cementing practices, management of materials and wastes on and off the site and careful siting resulting from location restrictions,

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setbacks and geologic studies, yield a low risk that ground and surface water supplies will be impacted either through surface spills or subsurface releases during the drilling and waste transport process. Risks from air emissions to humans were moderate resulting from the probability that NOx, benzene and particulate matter would be emitted from diesel engines used to power drill rigs and compressors. Air emissions from non-combustion sources such as tanks or spills were rated as low. However, insufficient consequence data were available to assign a risk ranking to air emissions associated with truck traffic.

Team Reports:

Appendix B: Air Emissions, Appendix C: Road Damage and Traffic, Appendix D: Drilling Fluids and Cuttings, Appendix F: Noise and Visual, Appendix H: Wells and Formations, Appendix I: Waste

Phase 3: Hydraulic Fracturing/Completion


During hydraulic fracturing, the horizontal section of the well is perforated by a series of explosive charges that create small fractures in the target formation in preparation for hydraulic fracturing. Then millions of gallons of water, added chemicals and particles known as proppant (usually sand that is mainly silica dioxide) are pumped down the well at high pressure to further fracture the shale. As the fracking water penetrates and enlarges the initial fractures created by the explosive charges, the included proppant fills the interstitial spaces of the created fractures and keeps them propped open so that produced gas can flow into the well. Once fracturing is complete, some of the injected fracturing fluids return to the surface as flowback. During the flowback period both hydraulic fracturing fluids and other naturally occurring materials contained in the formation migrate back through the borehole to the surface as a result of the overlying geological pressure. Pipelines (gathering lines) that transfer the gas to intrastate or interstate pipelines can be installed during this phase, but the impact of gathering lines is addressed in connection with the production phase.

Duration:

Hydraulic Fracturing: 5 days per well for the actual fracking - 2 days to mobilize and demobilize fracking equipment. (NY DEC 2011) Flowback: 3-10 days (average 6.5 days/well, U.S. EPA 2012) Venting/Flaring: 1 day to several weeks (U.S. EPA 2011) and completely or partially overlaps with the flowback phase.

Summary of Risks:

Truck traffic is most intense during this phase of UGWD because of the numerous tank truck loads of water that must be brought to the site for hydraulic fracking. For this reason, risks to communities and people from truck traffic are high due to the noise, vibration and cost to repair road damage. Other factors related to traffic such as accidents, damage to vehicles, delays and inconvenience continue to be moderate. There are concerns over the toxicity of chemicals used in fracing fluid and the potential for contamination of drinking water, surface water and ground water supplies. Pathways of contamination include spills, both on the pad and off the pad, subsurface releases from poorly constructed wells and improper management and transport of waste materials, both on the pad and off. The stringent controls on well casing and cementing, stormwater and spill management on the pad, proper siting using geologic studies and setbacks from sensitive ecological

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and community features are among the many best practices that reduce surface and ground water risks for people and the environment to low. The sources of air emissions increase during this phase to include inhalation of the silica proppant and additional combustion and non-combustions sources of air emissions required for hydraulic fracturing pumps and flaring events. Under the 75% extraction scenario, air emissions risks rise to high for both combustion and non-combustion emissions compared to the moderate risk ranking under the 25% extraction scenario because the activity will occur more often under the more intense development scenario. In addition, water appropriations pose a moderate risk to aquatic ecosystems because of the withdrawals of large amounts of water over compressed periods of time. There are uncertainties regarding how this may impact aquatic ecosystems which reflect sensitivities associated with time of year, breeding and spawning periods and drought conditions.

Team Reports:

Appendix B: Air Emissions, Appendix C: Roads and Traffic, Appendix E: Hydraulic Fracturing Fluids, Appendix F: Noise and Visual, Appendix G: Water Withdrawal, Appendix H: Wells and Formations, Appendix I: Waste

Phase 4: Production


Pipelines are needed to transmit the gas from the well to processing plants or intrastate or interstate transmission lines. Compressors may be necessary on site to provide the pressure necessary to move the gas through the gathering lines. Offsite compressors are also required to maintain necessary pressures to deliver gas to processing plants or intrastate or interstate pipelines. In addition, produced gas may need additional processing to prevent condensation/crystallization of liquid compounds in the gas gathering lines. This processing may occur both on-site, known as field processing, and off-site at centralized processing plants. Central processing plants provide further treatment to remove remaining liquids and to achieve desired methane concentrations. Downstream infrastructure such as liquefaction plants, central processing plants, transmission lines, etc. are outside the scope of this risk assessment.

Duration:

Approximately 20 years or more, although this is highly variable

Risk Summary:

During this phase, or possibly initiated in earlier stages, gas gathering lines will be installed to transport gas. Johnson (2010) estimates that 1.65 miles of gathering pipeline are needed for each new well pad. In Pennsylvania, this aggregate effect will impact an area larger than the cumulative area affected by all other Marcellus gas infrastructure and about half of that area will be forested. While the Comprehensive Gas Development Plan will serve to reduce the number of gathering lines installed and will minimize forest fragmentation through co-location with other linear infrastructure, there will be, by necessity and practicality, significant impacts to terrestrial and aquatic ecosystems. These risks to ecology have been rated moderate (under the 25% extraction scenario) to high (under the 75% extraction scenario) because the siting of gathering lines is not regulated and is dictated by the willingness of property owners to enter into lease or easement agreements. In addition, gathering lines are long term features on the landscape (spanning the production life of the well) and the likelihood of stream crossings is high. Compressors on and off the pad pose low to moderate risks to humans while impacts related to truck traffic are either non-existent or low. Subsurface releases of stray gas and fluids continue to be a risk to both humans and ecology. The stringent controls on well casing and cementing, stormwater and spill management on the pad, proper siting using

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geologic studies and setbacks from sensitive ecological and community features are among the many best practices that serve to reduce the risk of water contamination for human consumption to low except for the specific case of methane. Risks were evaluated for setbacks of 2,000 feet and 3,281 feet (1 kilometer) from the nearest drinking water wells. Risks to humans were rated as moderate for the 2,000 feet scenario because data are emerging that have found higher concentration of dissolved methane in drinking water wells closer to gas wells. Moderate risks associated with subsurface releases of fracturing fluid, flowback and produced water were noted for aquatic communities because these contaminants would be expected to remain in the groundwater and because of the sensitivity of pollution-intolerant aquatic life to low concentrations of salt and other chemicals. Insufficient data were available on the health consequences of air emissions produced from compressors because of uncertainties associated with location, fuel type and number needed. Moderate risks for air emissions were associated with high probabilities of exposure to combustion and non-combustion sources related to well pad and pipeline emissions, well unloadings. The consequences of truck traffic were determined to be minor.

Team Report:

Appendix B: Air Emissions, Appendix C: Roads and Traffic, Appendix F: Noise and Visual, Appendix G: Wells and Formations, Appendix I: Water Withdrawal

Phase 5: Well Abandonment/Reclamation

This phase was not assessed by all the teams but is included in the core document and risk assessment chart in Appendix A to address the entire lifecycle of the well pad.

Activity/Description

The goal of reclamation is to return the developed area to native vegetation (or pre-disturbance vegetation in the case of agricultural land) and restore the original hydrologic conditions to the maximum extent possible. Interim reclamation will follow construction and drilling to stabilize the ground and reduce opportunities for invasive species.

Duration

Interim reclamation follows immediately after last well on a pad moves into production. Final reclamation will occur over a 4 week period.

Risk Summary:

Air, water and soil contamination risks related to subsurface leaks in wells are low for both humans and ecology. Procedures for well plugging and abandonment are prescribed in COMAR 26.19.01.12 in order to prevent migration of stray gas along the wellbore and behind casing. Maryland’s best practices applies reclamation requirements to all disturbed land, including the pad, access roads, ponds, pipelines and locations of ancillary equipment which reduces the ecological and visual impacts associated with land clearing and forest fragmentation. Truck traffic and noise associated with reclamation activities will occur but will be minimal, posing low risks people, communities, wildlife and recreation.

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Conclusion

Risks are inherent in any type of mineral extraction, industrial and construction activity. Across the life-cycle of the well, from initial site identification to well abandonment and reclamation, UGWD encompasses a broad range of these activities. Maryland draws from its robust stormwater management, soil erosion and control, and water appropriations programs and examines the effectiveness of proposed best management practices for revising its existing gas and oil development regulations. Together, these existing and proposed practices serve to reduce many risks to western Maryland’s citizens, economy and its high quality water, air and natural resources. If risks are found to be unacceptably high, additional mitigation steps could be taken, or gas extraction in the Marcellus shale in Maryland could be deferred until risks can be reduced by new technology or practices, or until additional data demonstrate that the proposed practices are effective to reduce risk.

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< chesapeakeclimate.org/wp/wp-content/uploads/2014/02/Shale-gas-risk-assessment-for-Maryland_Feb2014.pdf >

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Program: Well Permit Issuance for Horizontal Drilling and High Volume Hydraulic Fracturing in the Marcellus Shale and Other Low

Permeability Gas Reservoirs. Albany: n.p, 2011. PDF file. http://www.dec.ny.gov/energy/75370.html

http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/Eshleman_Elmore_Final_BMP_Report_22113_Red.pdf


http://www.nature.org/media/pa/tnc_energy_analysis.pdf

http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf

http://www.dec.ny.gov/energy/75370.html

1

Appendix A

Risk Ranking: Summary Chart

Aspect Agent/

chemical Impact on Phase

Site

identification/ preparation

Drilling, casing and cementing

HVHF / Well completion

Production Well

abandonment/ reclamation

Blowout

Contamination of soil, ground

water or surface water by surface spill or release

Human Low Low Low Low NA

Blowout Explosion/fire/ contamination

Human NA Low Low Low NA

Combustion from pumps, drill rigs, and compressors

NOx, benzene, PM

Human NA Moderate

Moderate for Scenario 1; High for Scenario 2

Insufficient data

NA

Drilling through coalbed

Methane Ecological and Human

NA Low NA NA NA

Flaring CO2, PM Human NA NA Low NA NA

Non-combustion

VOCs, methane, NGLs

Human NA Low NA NA NA

Proppant use Silica Human NA NA Moderate NA NA

Releases from pipes, valves, fittings

Methane Community NA NA NA Moderate NA

Separators and storage tanks

VOCs, methane, NGLs

Human NA Low NA NA NA

2

Aspect Agent/


Site




Production Well


Storage of flowback, venting and separation events

Methane, H2S, VOCs, NGLs,

BTEX Human NA NA


NA NA

Truck trips Dust/PM Human Moderate Insufficient

data

Low for Scenario 1, Insufficient for Scenario

2

Moderate Low

Truck trips NOx, benzene,

PM Human

Low for Seismic

Assessment, Moderate

for Site Preparation

Insufficient data

Insufficient data

Moderate Low

Well unloadings

Methane, H2S, VOCs

Human NA NA NA Moderate NA

Contamination of soil, ground water or surface water by surface spill or release

Cuttings Ecological and Human

NA Low NA NA NA


Drilling additives Ecological and Human

NA Low NA NA NA


Drilling mud Ecological and Human

NA Low NA NA NA

3

Aspect Agent/


Site




Production Well



Fuel Ecological and Human

NA Low Low NA NA


Stored chemicals

Ecological and Human

NA Low Low NA NA

Saline intrusion during drilling

Brine Human NA Low NA NA NA

Subsurface releases or migration

Brine Ecological and Human

NA Low Low Low Low

Construction Erosion and

Sediment Ecological Low NA NA NA Low

Construction

Forest fragmentation, sediment, harm

to wildlife

Ecological and Farmland

Moderate NA NA NA Low

Gathering Lines

Forest fragmentation,

habitat fragmentation, harm to aquatic and terrestrial

species

Ecological NA NA NA


Low


Flowback Ecological and Human

NA NA Low NA NA

4

Aspect Agent/


Site




Production Well



Fracturing additives


NA NA Low NA NA


Fracturing fluid Ecological and Human

NA NA Low NA NA


Produced water Ecological and Human

NA NA Low NA NA


Flowback Ecological NA NA Moderate Low NA


Flowback Human NA NA Low Low Low


Fracturing fluid Ecological NA NA Moderate Moderate NA


Fracturing fluid Human NA NA Low Low Low


Produced water Ecological NA NA NA Moderate NA


Produced water Human NA NA Low Low Low

Noise / vibration

Casing Ecological and Human

NA Low NA NA NA

5

Aspect Agent/


Site




Production Well


Noise / vibration

Cementing Ecological and Human

NA Low NA NA NA

Noise / vibration

Compressors off the pad

Ecological NA Low NA Low NA

Noise / vibration

Compressors off the pad

Human / Community

NA NA NA Moderate NA

Noise / vibration

Compressors on the pad

Community, Ecological and Human

NA Low Low Low NA

Noise / vibration

Construction activity


Low NA NA NA Low

Noise / vibration

Drilling Ecological and Human

NA Low NA NA NA

Noise / vibration

Generators and pumps


NA Low Low Low NA

Noise / vibration

Vehicle traffic Ecological Low Low Low Low Low

Noise / vibration

Vehicle traffic Human / Community

Low Moderate High Low Low

Visual Drill rigs Human / Community

Low Low NA NA NA

Visual Land clearing Human / Community

Low NA NA Low Low

Visual Lighting Community, Ecological and Human

Low Low Low NA NA

Visual Well pad before

production Human / Community

Low Low Low NA NA

Visual

Well pad during production and

after reclamation

Human / Community

Low Low Low Low Low

Saline intrusion from casing and cement failure

Brine Human NA Low Low Low Low

6

Aspect Agent/


Site




Production Well



Methane Ecological NA Low Low Low Low

Subsurface releases or migration (gas well set back 2,000 feet from nearest drinking water well)

Methane Human NA Low Low Moderate Low

Subsurface releases or migration(gas well set back 1 km from nearest drinking water well

Methane Human NA Low Low Low Low

Traffic accidents Cumulative

Injury and death Community Moderate High High Moderate Moderate

Traffic Cumulative

Cost of repair of road damage

Community Low Moderate High Low Low

Traffic Cumulative

Damage to resident’s

vehicles from road damage

Community Low Low Moderate Low Low

Traffic Cumulative

Damage to wildlife

Ecological Low Low Low Low Low

Traffic Cumulative

Delay of emergency

vehicles Community Low Moderate High Low Low

Traffic Cumulative

Delays and inconvenience

(non-emergency vehicles)


Traffic Cumulative

Increased cost of policing


7

Aspect Agent/


Site




Production Well


Traffic Cumulative

Increased risk of roll-over, etc.

from road damage


Traffic Cumulative

Interference with outdoor

recreation Community Low Moderate Moderate Low Low

Traffic Cumulative

Loss of rural character


Disposal of wastewater in UIC wells

Flowback and Produced water

Groundwater

NA NA NA

NA in MD; Moderate in States with UIC wells

NA

Earthquake UIC wells Community NA NA

NA in MD, High in

States with UIC wells

NA NA

Waste disposal Drilling mud,

brine, cuttings, flowback


Low Low Low NA NA

Water appropriation

Withdrawals from surface or

groundwater

Ecological systems and aquatic species

NA Low Moderate NA NA

Water appropriation

Withdrawals from surface or

groundwater

Local and regional water supplies and recreational activities

NA Low Low NA NA

i

Appendix B Air Emission

Introduction ............................................................................................................................................................ 1

Regulatory Framework to Address Air Emissions ................................................................................................... 1

Proposed Best Management Practices (BMPs) ...................................................................................................... 2

Pertinent Chemical Characteristics of the Marcellus Shale in Maryland ............................................................... 8

Determining Risks During the Phases of Unconventional Gas Well Development (UGWD) .................................. 9

Phase 1: Site Assessment ..................................................................................................................................... 11

Activity/Description .............................................................................................................................................. 11

Emission Sources .................................................................................................................................................. 11

Activity Duration and Scope ................................................................................................................................. 12

Literature Review of Air Impacts .......................................................................................................................... 12

Risk Assessment ................................................................................................................................................... 12

Phase 2: Site Preparation ..................................................................................................................................... 13





Risks Assessment .................................................................................................................................................. 14

Phase 3: Drilling .................................................................................................................................................... 17




Literature Review of Emissions from Combustion Sources .................................................................................. 20

Risk Assessment ................................................................................................................................................... 22

Phase 4: Hydraulic Fracturing/Completion........................................................................................................... 25





Risk Assessment ................................................................................................................................................... 30

Phases 5 and 6: Production/Processing and Ancillary Infrastructure .................................................................. 34



Activity duration and Scope ................................................................................................................................. 37


Risk Assessment ................................................................................................................................................... 38

Risk of Cumulative Impacts or Synergistic Effects ................................................................................................ 41

Greenhouse Gases ................................................................................................................................................ 42

ii

Conclusions ........................................................................................................................................................... 43

References ............................................................................................................................................................ 45

1

Introduction

An emergence of new technologies, collectively known as unconventional gas well development (UGWD), has allowed industry to extract natural gas and oil from geological formations that were historically not economically viable. In some states these technologies, specifically hydraulic fracturing and horizontal drilling, facilitated an oil and gas boom before regulators were prepared with updated regulations or adequate staffing. At the same time concerns began to emerge on the health and environmental effects of chemicals, hazardous air pollutant emissions, noise, traffic, and other UGWD impacts. One of the nation’s largest shale gas formations experiencing UGWD is the Marcellus Shale, which underlies portions of the westernmost counties in Maryland. The Maryland Departments of Environment and Natural Resources conducted a qualitative risk assessment of the UGWD process to determine whether Marcellus natural gas can be extracted safely. This risk assessment (RA) focuses on air emissions associated with UGWD.

This RA evaluates air emissions during major phases of the UGWD process. These phases include: site

assessment, site preparation, drilling, hydraulic fracturing/completion, gas production/processing, and ancillary infrastructure (the reclamation phase was not considered as the site will be returned to pre-drilling conditions and no significant emissions are expected). Each phase of the UGWD process is described and the sources of air emissions identified. The duration and scope of the activity are also described and, where possible, estimated using two different development scenarios of 150 and 450 wells. These scenarios were developed by MDE and the Towson University Regional Economic Studies Institute (RESI) for use in RESI’s study on the potential economic impacts of Marcellus gas, and estimate the number of wells and pads necessary to extract 25 percent and 75 percent of the available gas over a ten year period. A literature review of the air impacts associated with each activity is presented and then the current regulations/proposed best management practices (BMPs) to address those impacts are considered. A qualitative RA is then presented that considers the probability and consequence of impacts after consideration of applicable regulations and recommended BMPs.

Specific air emission risks the Departments were tasked to assess include: (1) combustion emissions from on

and off-site vehicles, compressors and other equipment on the well pad; (2) noncombustion emissions such as volatile organic compounds (VOCs) and methane from wells during drilling and hydraulic fracturing/completion; (3) particulate emissions from traffic on unpaved roads; and, (4) accidents like well blowouts. Where other public health or environmental risks were identified during scientific literature review of UGWD, they were also included in the RA. This RA considers air emissions from some infrastructure beyond the well pad, such as gathering lines and compressors associated with gathering lines, but does not consider infrastructure further afield such as intrastate or interstate transmission pipelines, centralized processing or liquefaction plants, or distribution systems. The RA addresses potential exposures to human and environmental receptors beyond the well pad as these are within the purview of the Departments. The RA does not consider exposure to workers on the well pad as these are regulated by the federal Occupational Safety and Health Administration of the Maryland Department of Labor, Licensing and Regulation.

Regulatory Framework to Address Air Emissions

Air quality in the United States is regulated under the federal Clean Air Act (CAA). The CAA generally divides pollutants into two categories, criteria and non-criteria pollutants. For criteria pollutants (nitrogen oxides, sulfur oxides, carbon monoxide, particle pollution, lead and ground level ozone), EPA has established national ambient air quality standards (NAAQS) that establish levels of pollutants in the air that are protective of human health and welfare.

2

The CAA also has National Emissions Standards for Hazardous Air Pollutants (NESHAPs). EPA has not set ambient air concentrations for hazardous air pollutants (HAPs), often referred to as non-criteria pollutants. Instead, HAPs are regulated using a technology-based approach. Under this approach EPA identifies categories of sources for 187 hazardous air pollutants and requires those sources to implement the current best available technology. Every 8 years, EPA is required to determine if there are any residual risks for a particular source category and revise, as necessary, standards to address remaining risks. EPA promulgated new Standards of Performance for Crude Oil and Natural Gas Production, Transmission and Distribution in 2012 (78 FR 184).

The CAA divides emissions sources into stationary (e.g., factories, power plants) and mobile (e.g., cars, trucks,

buses and non-road equipment) sources. Permits are issued for stationary sources or sources that remain in place for 12 or more months and where new or modified emissions exceed established amounts. Emissions standards for mobile sources are set by EPA, not states, and are regulated by requiring manufacturers to build cleaner cars, by reducing pollutant contents of fuels, and by requiring emissions inspection and maintenance programs in non-attainment areas. Currently, mobile sources account for half of the emissions of volatile organic compounds (VOCs), more than half of the emissions of nitrogen oxides, half of the HAPs emissions, and 75 percent of the carbon monoxide emissions nationwide (U.S. EPA, 2007).

For areas that are in attainment of NAAQS, the CAA requires that any new or modified stationary sources of

air pollution not cause a significant deterioration of air quality. The CAA includes provisions to ensure that emissions from one state are not contributing to public health problems in downwind states. The CAA also allows states the ability to have stronger air pollution laws for stationary sources than provided for by the act. States with pollutant levels exceeding one or more of these standards are considered in nonattainment and are required to develop state implementation plans to achieve NAAQS.

Maryland has adopted all of the NAAQS in Title 26, Subtitle 11, Chapter 4, Section 2 of the Code of Maryland

Regulations (COMAR 26.11.04.02). In addition, Maryland has defined a State Ambient Air Quality Standard for fluorides (COMAR 26.11.04.01). The State Ambient Air Quality Standard for fluorides, however, is not considered in this assessment because no emissions of fluorides are expected. Garret and Allegany Counties are currently in attainment of NAAQS, while the Baltimore region is in non-attainment of several standards. Upwind states are large contributors to air pollutants in Maryland that impact not only public health but also water quality in the Chesapeake Bay.

Maryland has other regulations that also help address air pollution. These include the following

Regulations requiring listing all equipment available for the detection, prevention, and containment of gas leaks and oil spills (COMAR 26.19.01.06C(17)).

Regulations establishing MDE’s authority to not issue a drilling and operating permit if drilling or operations would result in physical and preventable loss of oil and gas (COMAR 26.19.01.09J).

Sediments and erosion control regulations that help address dust generated during soil disturbance (MDE 2011)

Proposed Best Management Practices (BMPs)

In addition to the current regulations addressing stationary and mobile sources, the Departments are proposing additional best management practices, monitoring and setbacks to address air pollution sources. The current regulations and proposed BMPs are identified in Table 1,

Table 2, and Table 3, below, and are grouped according to the types of emission sources they are designed to

address. These tables also categorize the BMPs according to effectiveness and the phase(s) of operations to which they apply.

3

The following general principles were used to evaluate BMP implementation effectiveness:

BMPs that require implementation of defined best available control technologies (BAT) that have proven efficiencies at the start of operation are expected to mitigate risks to a greater degree than BMPs that require plans, time limitations to activities, reporting requirements, or general guidelines.

BMPs that require implementation of a specific BAT should be distinguished from BMPs that provide flexibility for BAT implementation, as the latter is expected to result in site-specific efficiencies that may be difficult to verify and enforce.

The availability, or lack-thereof, of literature or data confirming efficiencies of technology-based BMPs is considered when determining risk mitigation.

BMPs that require documented plans are generally expected to identify measures that avoid or reduce impacts, though they may allow exceptions and require Departmental resources for plan review and compliance measures.

BMPs that require reports or documentation, suggest limits to certain activities, and/or recommend certain measures are generally expected to have limited effectiveness because they are not prescriptive and can be difficult to verify or enforce.

4

Table 1: BMPs for Combustion Sources

Current Regulation or Proposed BMP BMP Effectiveness Phase(s) of Operations

Fuel Content: Ultra-Low Sulfur Diesel (ULSD) fuel (maximum sulfur content of 15 ppm) BAT startup All

Engine Combustions: Current clean air act regulations for mobile road and non-road engines Depends on current fleet composition whether BAT start-up or in the future

All

Idling: Limit unnecessary idling to 5 minutes for both road and nonroad engines (exception for nonroad engines kept in ready reserve).

Guidelines/Behavioral All

Power Plan: Require that applicants provide a power plan that results in the lowest practicable impact from the choice of energy source. This will include requirements that electricity be used from the grid or alternatively propane or natural gas, whenever possible

Reporting/ Documentation

All

Flares Must use: Raised/elevated flares or engineered combustion device with a 98 percent destruction efficiency of methane. No pit flaring is permitted. No flaring for more than 30-days on any exploratory or extension wells (for the life of the well) No visible emissions, except for periods not to exceed a total of five minutes during any two consecutive hours.

Combination of BAT startup and time limits.

Hydraulic fracturing/ completion

5

Table 2: BMPs for Non-combustion Sources

Current Regulation or Proposed BMP BMP Effectiveness

Phase(s) of Operations

Venting: Green completion shall be achieved on all gas wells drilled in Maryland. In green completions, gas and hydrocarbon liquids are physically separated from other fluids and delivered directly into equipment that holds or transports the hydrocarbons for productive use. Reduced Emissions Completions shall also be required for re-fracturing.

BAT startup

Hydraulic fracturing/ completion

Storage Tanks: Except for tanks used in a closed loop system for managing drilling fluid and cuttings, which may be open to the atmosphere, tanks shall be closed and equipped with pollution control equipment specified in other sections of this report. Tanks must meet EPA’s New Source Performance Standards.

BAT startup Processing, Production

Compressors Certain compressors, namely single centrifugal compressor using wet seals that is located between the wellhead and the point of custody transfer to the natural gas transmission and storage segment (not at the well site), are required to reduce VOC emissions by 95% (40 CFR Part 60, Subpart OOOO).

BAT startup Production

Leaks Leak Detection and Repair Program from wellhead to transmission line to include: Conforming to EPA’s Natural Gas STAR program guidelines and EPA’s best practice guidelines for leak detection and repair Listing all equipment available for the detection, prevention, and containment of gas leaks and oil spills (COMAR 26.19.01.06C(17)). MDE may not issue a drilling and operating permit if drilling or operations would result in physical and preventable loss of oil and gas (COMAR 26.19.01.09J). On site air pollution monitoring, discussed in the monitoring section, shall be included as an element of the leak detection program.

BAT startup Production

Leaks All pipelines and fittings appurtenant thereto used in the drilling, operating or producing of oil and/or natural gas well(s) shall be designed for at least the greatest anticipated operating pressure or the maximum regulated relief pressure in accordance with the current recognized design practices of the industry.

Guidelines Production

Dust from Vehicle Traffic Dust suppression guidelines from PA DCNR Guidelines for Administering Oil and Gas Activity on State Forest Lands (2011).

Guidelines/ behavioral

All

6

Dust from Soil Disturbance Maryland’s sediments and erosion control regulations

Guidelines/ behavioral

Site preparation

Table 3: BMPs for Both Sources

Current Regulation or Proposed BMP BMP Effectiveness

Phase(s) of Operations

Comprehensive Gas Development Plans Planning BMP All

Construction/Operations Plan: For each well, the applicant for a drilling permit shall prepare and submit to MDE, as part of the application, a plan for construction and operation that meets or exceeds the standards and/or individual planning requirements for Engineering, Design and Environmental Controls set forth in Section VI.

Planning BMP All

Top-Down BAT: The Department of the Environment intends to require top-down Best Available Technology (BAT) for the control of air emissions. This means that the applicant will be required to consider all available technology and implement BAT control technologies unless it can demonstrate that those control technologies are not feasible, are cost-prohibitive or will not meaningfully reduce emissions from that component or piece of equipment. BAT emissions control technology will be mandatory for workovers1 . MDE will analyze top-down BAT demonstrations from applicants and approve the applicants BAT determination before a permit is issued. This includes all air pollution control elements in the EPA STAR program, and therefore the Departments are not proposing a separate requirement to participate in this voluntary EPA program.

BAT Startup All

Well Blowouts Blowout prevention equipment shall be: (1) Installed before drilling the plug on the surface casing; (2) Tested to a pressure in excess of that which may be expected at the production casing point before: (a) Drilling the plug on the surface casing; and (b) Penetrating the target formation; and (3) Tested on a weekly basis according to standard operating practice ( COMAR 16.19.01.10Q). Maryland is proposing a BMP that blow out preventers be installed and tested to ensure they can handle pressures at least 1.2 times the highest pressure normally experienced during the life of the blow out preventer or at least 1.2 times higher than the pressures experienced during well stimulation, whichever is greater.

BAT startup

Drilling, Hydraulic fracturing/ completion, processing, production

1 Workovers include the repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of

hydrocarbons; it includes refracturing.

7

Expanded Monitoring If leak detection monitoring identifies releases of contaminants, additional air monitoring may be required. Applicants may be required to demonstrate compliance with state air toxics regulations. They would need to estimate emissions, use models, and show offsite concentration of air pollutants below health thresholds.

BAT startup All

Setbacks Well must be set back 1,000 feet from the boundary of the property on which it is located, unless the Department grants a variance. Occupied buildings – 1,000-feet from a compressor, 1,000-feet from edge of disturbance. A setback of at least 2,000 feet from the edge of pad disturbance to any private well. (This BMP was not directed toward air emissions, but the setback will have the co-benefit of reducing the amount of air pollution that will reach a residence.) Aquatic habitat and special conservation areas - 450 and 650-feet, respectively, from edge of drill pad disturbance.

BAT Startup All

8

Pertinent Chemical Characteristics of the Marcellus Shale in Maryland

Studies by the National Energy Technology Laboratory (NETL, 2011) and others (Repetski et al., 2005) indicate

that the thermal maturity of the Marcellus play, represented by vitrinite reflectance values (R0%), increases eastward. R0% values greater than 1.6 are indicative of dry gas with few natural gas liquids (NGLs). Data from Maryland (Figure 1) indicate that R0% values are greater than 2 and indicative of dry gas. Dry gas consists of about 95 percent methane, 3 percent ethane, propane, and butane, and 2 percent non-hydrocarbon gases such as carbon dioxide, nitrogen, or helium (EPA, 2010). Wet gas can contain up to 20 percent of ethane, propane, and butane, and requires processing to remove NGLs before it can be distributed to consumers.

Since dry gas is expected to contain few natural gas liquids (NGLs), minimal processing will likely be necessary

on well pads in Maryland. Processing of NGLs requires storage tanks on well pads that can result in potentially harmful emissions of volatile organics compounds such as benzene, toluene, ethylbenzene and xylene (BTEX). However, benzene and other volatiles can potentially be present in dry gas and released to the atmosphere wherever dry gas is emitted or incompletely combusted. Emissions of BTEX compounds are therefore assumed in this risk assessment.

Figure 1: Vitrinite reflectance values (R0%) for Devonian Shale

Devonian Shale Maturity Ro% Data Repetski et al. 2002, 2004, 2005; Engelder 2008

9

Determining Risks During the Phases of Unconventional Gas Well Development (UGWD)

This section describes the major operational phases of the UGWD process, associated sources of air emissions,

the duration and scope of activities specific to each phase, a current literature summary of the pollution potential and health risks associated with phase-specific emissions, and consideration of Maryland’s current regulations and proposed BMPs followed by a qualitative risk assessment for each phase.

In assessing the risks associated with each UGWD phase, both the probability and consequences of air

emissions are considered. Table 4and Table 5 below contain the definitions of terms used to classify emissions risks. The probability of air emissions is determined through evaluation of the scope and duration of activities in each phase. So for example, phases with year-round emissions have a higher probability than phases that are short-duration. The consequences of air emissions impacts during each phase are primarily determined from results of the literature reviews and how effective current and proposed BMPs are expected to be in terms of mitigating risks.

Table 4: Probability of Air Emissions

Low Rarely happens under ordinary conditions; not forecast to be encountered under foreseeable future circumstances in view of current knowledge and existing controls on gas extraction

Moderate Occurs occasionally or could potentially occur under foreseeable circumstances if management or regulatory controls fall below best practice standards

High Occurs frequently under ordinary conditions


Lack of available data to confidently assign probability

Table 5: Consequence of Air Emissions

Minor Slight adverse impact on people or the environment; causes no injury or illness

Moderate Considerable adverse impact on people or the environment; could affect the health of persons in the immediate vicinity; localized or temporary environmental damage

Serious Major adverse impact on people or the environment; could affect the health of persons in a large area; extensive or permanent environmental damage


Lack of available data to confidently assign consequence

10

Two scenarios are used to determine the scope and duration of air emissions during each UGWD phase. These scenarios assume 25 percent and 75 percent extraction levels of the available Marcellus resource in Maryland. These scenarios, in addition to equipment levels identified from literature sources, were used to determine the likely scope and duration of each phase. Table 6 and Table 7, below provide scenario details.

Table 6: Extraction Level Scenarios for the Marcellus Shale in Maryland.

Item Scenario 1 Scenario 2

Extraction Level 25 percent 75 percent

Wells per pad 6 6

Average Wells Drilled/Year 15 45

Total Wells Drilled 150 450

Total Number of Well Pads 25 75

Table 7: Detailed Breakdown of Scenarios by Year.

Year

Number of New Wells Drilled

Number of New Well Pads

Total Number of Wells

Total Number of Well Pads

2017 8 4 8 4

2018 16 4 24 8

2019 29 3 53 11

2020 22 3 75 14

2021 18 3 93 17

2022 15 2 108 19

2023 12 2 120 21

2024 12 2 132 23

2025 12 2 144 25

2026 6 0 150 25

Yearly Avg.

15 2.5

In addition to the scenario assumptions, a few additional assumptions were made based upon information

contained in New York’s SGEIS and information gathered from draft permits for UGWD submitted to the Departments. These assumptions include the following:

15-acres of total site disturbance/land clearing per well pad, 4 of which are associated with the footprint of the well pad and road;

5,000,000-gallons of water used to hydraulically fracture each well and a 30 percent (1.5 million gallon) flow back rate. This information was used to estimate the number of truck trips necessary to deliver freshwater and transport flowback fluid. This is a conservative assumption as flowback water may be recycled for successive hydraulic fracturing events on a well pad.

Year

Number of New Wells Drilled

Number of New Well Pads

Total Number of Wells

Total Number of Well Pads

2017 36 12 36 12

2018 72 12 108 24

2019 63 9 171 33

2020 54 9 225 42

2021 63 9 288 51

2022 42 6 330 57

2023 36 6 366 63

2024 36 6 402 69

2025 36 6 438 75

2026 12 0 450 75

Yearly Avg.

45 7.5

11

Phase 1: Site Assessment


Prior to conducting any drilling activities in a region, oil and gas companies routinely perform seismic assessment surveys to target the best locations for drilling exploratory/production wells. For the purposes of describing the nature of this activity and potential impact to air resources a permit application submitted to MDE by the PA General Energy Company (PAGEC) was reviewed. PAGEC established an approximately 3.9-mile transect along which the seismic survey would be conducted. A survey crew was deployed to lay out the transect line using traditional survey equipment. This was done on foot with minimal disturbance to the landscape. Survey flagging and pin flags were used to mark out the survey line. The second phase entailed using a three-man crew and rubber-tired or track mount drill buggy (Figure 2). A four inch hole (referred to as a “shotpoint” hole) would be drilled to a 20-foot depth and then loaded with a 2.5-pound biodegradable charge. If a 20-foot hole could not be drilled, then three 10-foot holes would be drilled each containing a one-pound charge. These holes would then be filled with bentonite pellets with a hole plug used for the last 36-inches. In areas inaccessible by buggy, a cluster of seven 5-foot holes are dug with a 1/3 charge. These shotpoint holes are drilled every 110-feet for the first and last seven holes of the transect and 220-feet for the remainder of the shotpoints.

Figure 2: Drill Buggy (Photo courtesy of http://www.bertramdrilling.com/buggy.html)

The third phase involves collecting the seismic data. This entails a 15 to 20 man crew traversing the survey line on foot and potentially using an ATV to move equipment. The recording crew will lay out receivers and geophones along the survey route to record seismic data. Once the recording equipment is laid out the charges will be detonated individually and the recordings taken. When this has been completed, the crew removes recording equipment, flagging and pin flags.

Emission Sources

Combustion Sources

Mobile Nonroad Sources: Drill buggy - Cat 3116 engine (200 HP) – see http://www.bertramdrilling.com/files/Terra%20Buggy.pdf

Mobile Road Sources: Trucks used to deliver equipment to seismic assessment site. Non-Combustion Sources N/A Accidents N/A

http://www.bertramdrilling.com/buggy.html

http://www.bertramdrilling.com/files/Terra%20Buggy.pdf

12

Activity Duration and Scope

Duration:

Up to 120 days, based upon maximum length of time indicated from a draft permit application in Maryland.

Scope:

Do not anticipate that seismic survey activity will increase appreciably from the 150 well to the 450 well scenario as a single survey application from PA General Energy Company covered an approximately 3.9-mile transect.

Literature Review of Air Impacts

No literature sources quantifying air emissions from seismic survey assessments were found. This is most likely due to the narrow scope of activity and few emissions sources with low overall loads.

Risk Assessment

Any air impacts associated with seismic assessment operations result from internal combustion engine emissions and are presented in Table 8. These emissions are generated from mobile road sources used to deliver equipment to the site and non-road sources used to perform the drilling/seismic thumping procedures and traverse the transect line. However, few pieces of equipment are used to assess a wide geographic area resulting in negligible air emissions. In addition, existing Clean Air Act regulations for mobile road and non-road sources require standardized control technologies to address these sources and no literature could be found indicating any air impacts from the seismic assessment phase. As a result these facts, the probability of occurrence is considered low and the potential consequences minor.

Table 8: Risk Assessment for Phase 1 – Seismic Assessment

Scenario Duration Scope Emissions Type

Pollutants of Concern

Impact Probability

Consequence

Risk Ranking

Same for both Scenarios

120 days 1 drill buggy or “thumper” truck and associated trucks necessary to bring these on site.

Combustion from engines

NOx, PM Human (Inhalation)

Low Minor Low

13

Phase 2: Site Preparation


Site preparation involves clearing, leveling, and excavation (Figure 3) at a well site to install the well pad, freshwater pits, and any associated access roads. The Department reviewed language from one of Maryland’s draft permit applications for gas well development that describes these activities as follows: Estimate earthwork will be done in 2 contractor mobilizations – the first mobilization is for constructing the fresh water pit, well pad and access roads; the second mobilization will happen when the site is reclaimed after well drilling. First filter fabric is installed around site perimeter, then clear and grub areas required for access roads and well pad. Strip topsoil and place in stock piles. Proceed to grading and compacting using rollers/sheepsfoot. After final grading is complete and the site has been mulched/seeded, perimeter controls can be removed with County approval. Also, place down geotextiles and crushed stone for the well pad and roads.

Figure 3: Excavation/Earth Moving Equipment (Photo courtesy of www.co.monterey.ca.us/.../gr ade/grading_powerpoint_060805.pps)

Emission Sources

Combustion Sources Mobile Nonroad Sources: general construction equipment (bull dozers, graders, loaders, dump trucks, and clearing equipment) powered by diesel engines. Mobile Road Sources: Trucks used to deliver equipment to the site. Non-Combustion Sources Fugitive dust/particulate emissions from earth moving and road traffic. Accidents N/A


Duration:

Up to 4 weeks per multi-well pad (NYSDEC, 2011)

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Scenario 1: Average of 15 new wells/year. Using six wells per pad results in an average of 2.5 multi-well pads/year = 10 weeks/yr. of site prep. A maximum of 4 pads in a year results in 16 weeks/yr of activity. Scenario 2: Average of 45 new wells/year. Using six wells per pad results in an average of 7.5 multi-well pads/year = 30 weeks/yr. of site prep. A maximum of 12 pads in a year results in 48 weeks/yr of activity.

Scope:

Pads may be widely spaced. A common assumption is no more than one well pad per square mile. We assumed a total average disturbance of 15-acres per multi-well pad and following the assumption of 45 heavy trucks and 90 light trucks (Table 9) for drill pad construction based upon modified information from New York (NYSDEC, 2011), which can be seen in below:

Table 9: Estimated truck trips during Phase 2 Site Preparation.

Scenario 1: An average of 2.5 pads/year to a max. of 4 pads/year results in anywhere from approximately 113 to 180 heavy truck trips/year and 225 to 360 light truck trips/year. Total area disturbed/year is 38-acres on average with a maximum of 60-acres in any given year. There will likely be simultaneous emissions from site preparation at different pads. Scenario 2: An average of 7.5 pads/year to a max. of 12 pads/year results in 338 to 540 heavy truck trips/year and 675 to 1080 light truck trips/year over ten years. Total area disturbed/year is 113-acres on average with a maximum of 225-acres in a year. There will likely be simultaneous emissions from site preparation at different pads.


There was scant literature found on site preparation activities associated with well pad development for oil and gas production specifically, but site clearing and grading impacts for the construction industry are well documented. Potential air impacts associated with construction site preparation include: (1) mobile source combustion emissions that contain particulate matter, nitrogen oxides and hazardous air pollutants; (2) particulate emissions resulting from soil disturbance and suspension; and, (3) greenhouse gas emissions (carbon dioxide and nitrous oxide emissions (Sacramento Air Quality District, 2009)

Risks Assessment

Air impacts during this phase are associated with combustion emissions from equipment delivery as well as during site clearing, grading, excavation, road and well pad construction. Diesel exhaust (DE) is one of the largest U.S. sources of fine particulate matter and also contains ozone-forming nitrogen oxides and toxic air pollutants (”Diesel Engine Exhaust”). DE has been classified by EPA as having chronic non-cancer (exacerbates asthma and other respiratory conditions, neurological effects, growth and survival) and carcinogenic (lung cancer, mutagenic/chromosomal) effects from inhalation (U.S. EPA, 2003b). Dust/particulate emissions are also generated when disturbing soil and handling aggregates used in well pad or road construction. However, little information is available regarding overall exposures and environmental or human health effects of combustion or dust emissions specifically from well pad site preparation.

Well pad activity Equipment

Heavy trucks Light trucks

Drill pad construction 45 90

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To better understand the magnitude of development from well pad site preparation activities, it is helpful to look at overall development statistics for Allegany and Garrett Counties. The Maryland Department of Planning (2010) publishes land use data, in acres for 1973, 2002 and 2010. The categories are developed land (residential, commercial, industrial, institutional, transportation, other) and non-residential) and resource land (agricultural, forest, extractive/barren/bare, wetland).

Table 10: Land Use in Allegany and Garrett Counties

Category 1973 2002 2010

Total developed lands (Allegany) 21059 32468 35853

Total resource land (Allegany) 245630 234316 230930

Total land (Allegany) 266689 266784 266783

Total water (Allegany) 2820 2725 2725

Total developed lands (Garrett) 13368 37689 41797

Total resource land (Garrett) 406425 381603 377496

Total land (Garrett) 419293 419293 419293

Total water (Garrett) 5635 5767 5767

These data indicate that the percentage of total land developed in Allegany County increased from 1973 to 2010 from 7.9 percent to 13.4 percent and approximately 14,794 acres were developed during that time. Under scenario 2, the build out predicted for Allegany County is 10 well pads; if each well develops 15 acres, 150 acres would be developed, or 0.06 percent of all the land in the County. Garrett County is larger and less developed than Allegany County. Garrett County is predicted to support 65 well pads under scenario 2. The percentage of total land developed in Garrett County increased from 1973 to 2010 from 3.2 percent to 10 percent and approximately 28,429 acres were developed during that time. If 65 well pads are constructed, 975 acres would be developed, representing 0.23 percent of land in the County. The probability of combustion emissions (Table 11) are considered high since they will occur routinely from site preparation activities. However, the relatively limited scope and duration of site preparation activities coupled with current technology-based Clean Air Act regulations for mobile vehicle sources reduces overall human health and environmental consequences to minor levels. Maryland also has standards and specifications for sediment and erosion control (MDE 2011) to help address dust control measures during site preparation. Proposed setbacks from property lines and occupied residences also help reduce direct human exposure to particulate matter and hazardous air pollutants associated with diesel exhaust emissions.

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Table 11: Risk Assessment for Phase 2 – Site Preparation.

Scenario Duration Scope Emissions Type Pollutants of Concern

Impact On Probability Consequence Risk Ranking

Scenario 1 10-16 Weeks

225-360 Trucks

Combustion from engines NOx, benzene, PM

Human (Inhalation)

High Minor Moderate

Fugitive dust from earth moving and truck traffic on unpaved roads.

PM

Scenario 2 30-48 Weeks

675 – 1080 Trucks

Combustion from engines NOx, benzene, PM

Human (Inhalation)

High Minor Moderate

Fugitive dust from earth moving and truck traffic on unpaved roads.

PM

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Phase 3: Drilling


After the site has been prepared and the drilling pad installed, one or more drill rigs (Figure 4) are brought on-site to conduct well drilling. Drilling entails creating a vertical bore hole approximately 2-3km deep, and then drilling horizontally up to 4km. In order to lubricate the drill bit and bring drill cuttings to the surface, fluid mud or air is used. In NY, most vertical drilling is done using air while the horizontal drilling typically uses mud (NYSDEC, 2011, p.5-32) . Drill cuttings come to the surface along with the drilling muds and are pumped into a machine that separates the cuttings from the mud so that the mud can be reused. Methane encountered when drilling can infiltrate drilling muds and be brought to the surface. A mud gas separator is used to separate introduced gas from drilling muds which can result in emissions of methane and associated compounds. When air drilling occurs, there is also a potential for particulate matter emissions from pulverized rock being blown out of the well bore.

Figure 4: Drill Rig (Photo courtesy of the Colorado Oil and Gas Conservation Commission).

Drill rigs are also used to case the well bore. Typically, three levels of casing (surface, intermediate, and production) are used in a telescoping fashion: (1) the surface casing is run from the land surface to below the deepest freshwater layer; (2) the intermediate casing is run from the surface casing down to the target formation; and, (3) the production casing is run from the intermediate casing through the target formation. All casing strings are cemented in place to stabilize the well string and also seal the annular space between the casing and borehole to prevent gas or fluid migration between geologic strata. A blow-out prevention system is often installed on top of the surface casing in order to control well pressure during drilling in case of a sudden gas release, called a gas “kick’ (“Natural Gas-From Wellhead to Burner Tip”). After the casing and cement are in place, the drilling rig is replaced by a temporary wellhead and the well is prepared for perforation by flushing with acid to remove cement and other debris. Freshwater is often

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delivered to the site during the drilling phase and for the hydraulic fracturing phase that follows via tank trucks. Tanks that store flowback from hydraulic fracturing may also be delivered during the drilling phase.

Figure 5: Typical Tank for Hauling Water (Photo courtesy of http://www.jjbodies.com)

Emission Sources

Combustion Sources Drill Rig Engine/Compressor – New York (NYSDEC, 2011) cites a 5,400 hp diesel drill rig with year-round emissions. Emissions from trucks used to deliver drilling fluids, chemicals, fracking water, and cement and to move equipment on site. Non-Combustion Sources Methane and associated chemical release directly to air during drilling (gas “kick”) and/or from mud/gas separator Dust/particulates re-suspended from air drilling and truck traffic on unpaved roads during freshwater and tank/equipment delivery. Accidents/Spills Blow-out during well drilling


Duration:

Up to 5 weeks (NYSDEC, 2011, p. 5-27) per well. Scenario 1: Assuming 6 wells drilled simultaneously on an average of 2.5 pads results in 30 weeks (6 wells X 5 weeks/well) of drilling. Scenario 2: Assuming 6 wells drilled simultaneously on an average of 7.5 pads results in 30 weeks (6 wells X 5 weeks/well) of drilling.

Scope

One small and one large drill rig are assumed to be used to drill each well. There also may be one mud gas separator per well pad. The truck trips per well, modified from NY (NYSDEC, 2011), are estimated below at 1889 truck trips (Table , 1283 heavy trucks, 606 light trucks) per well. To scale up to the estimated 6 wells per pad results in a total of 10,194 trips ( Table , 7,118 heavy trucks, 3,076 light trucks) per 6-well pad.

http://www.jjbodies.com/

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Table 12: Truck trips for drilling one well on a pad.

Table 13: Truck trips for drilling 6 wells on a pad.

Well pad activity Early well pad scenario (All water transport by truck)


Rig mobilization 190 280

Drilling fluids 270

Non-rig drilling equipment 90

Drilling (rig crew, etc.) 300 840

Completion chemicals 120 1956

Completion equipment 10

Hydraulic fracturing water hauling 6000*

Hydraulic fracturing sand 138

TOTAL truck trips per well pad (6 wells) 7118 3076

Sources: NYSDEC 2011, NTC Consultants 2011, All Consulting, 2010. *Modified from All Consultants 2010 to account for 5,000,000 gallons/well and 5,000 gallons/truck.

Scenario 1: 15 wells/year with likely simultaneous emissions from well drilling on different pads at the same time. Assuming wells are on multi-well pads results in total truck trips of approximately 25,485 (10,194 trips X 2.5 well pads) per year. Also, assume total emissions from 15 drill rigs (one per well). Assume 3 mud/gas separators at 1 for each well pad at 2.5 pads. Scenario 2: 45 wells/year with likely simultaneous emissions from well drilling at different pads at the same time. Assuming wells are on multi-well pads results in total truck trips of approximately 76,455 (10,194 trips X 7.5 well pads) per year. Also, assume total emissions from 45 drill rigs (one per well). Assume 8 mud/gas separators at 1 for each well pad at 7.5 pads.




Drilling fluids 45

Non-rig drilling equipment 45



Completion equipment 5

Hydraulic fracturing water hauling 1000*

Hydraulic fracturing sand 23

TOTAL truck trips During Drilling (1 well on 1 pad) 1283 606

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Literature Review of Emissions from Combustion Sources

The State of New York Supplemental Generic Environmental Impact Statement (NYSDEC, 2011) is the only study found where modeling of combustion emissions during drilling was performed. One very important limitation to this modeling analysis was that it did not include simultaneous emissions impacts from trucks used to transport fracking water, tanks and other equipment to the well pad. Therefore, the only modeled source in NY’s analysis was emissions from the drilling rig itself and an onsite compressor. Conservative assumptions (i.e., year-round continuous operation at a well pad) were built into New York’s modeling and interested parties can refer to that documentation for additional details. The results of NY’s modeling for combustion sources of criteria pollutants are presented below. Noncriteria pollutant emissions found by other studies during drilling are also discussed.

Criteria Pollutants

Particulate Matter The Tier 1 drilling rig engine/compressor modeled by NY exceeded 24-hour PM2.5 standards up to 120-meters away. (NYSDEC, 2011, p. 6-143) NO2 The Tier I drilling rig engines modeled by NY exceeded the NO2 1-hour standard by a factor of 2 up to 150-meters away unless equipped with particulate traps and selective catalytic reduction technology to meet standards. (NYS DEC, 2011, p. 6-150) SO2 No impacts expected due to use of ultra low sulfur fuel.

Non-criteria Pollutants

Non-criteria pollutant emissions considered during the drilling phase result from any fugitive natural gas that escapes through the borehole during drilling (i.e., gas “kick” or seepage from the formation), that is entrained and released from the drilling muds used to drill the well, or as a result of a catastrophic event such as a well blow-out. These emissions will vary depending upon the specific geology at a drill site and the associated quantities of gas and related chemicals at a particular well. This variability makes emission impacts difficult to model and assess. However, a recent study (Caulton et al., 2014) found large emissions averaging 34 grams of methane per kilometer per second during the drilling phase of operations. These recent estimates are 2-3 orders of magnitude higher than EPA estimates for this phase of operations. This study surveyed drilling emissions in areas predominately underlain by coal beds and more study is needed to determine whether calculated emissions rates are typical of gas well drilling generally. Another recent study (Colburn et al., 2012) in Colorado found non-methane hydrocarbons (NMHCs) emissions to be highest during this initial drilling phase. Since Maryland’s portion of the Marcellus is expected to be comprised of dry gas with little natural gas liquids, NMHC emissions measured in the Colorado study may not be representative of potential drilling emissions in Maryland. Table 14 below identifies the frequency of well blowouts documented by the International Association of Oil and Gas Producers for off-shore wells. Offshore well data were used because these were more robust data compared to data from relatively new onshore unconventional gas wells. This table identifies the number of blowout incidents for exploration and development drilling in shallow and deep natural gas reservoirs as follows: blowouts during exploration drilling in shallow gas reservoirs (22 per 13,762 = .0016 or 1.6 incidents per 1,000 wells); blowouts during development drilling in shallow gas reservoirs (23 per 22,833 = .001 or 1 incident per 1,000 wells); blowouts during exploration drilling in deep gas reservoirs (29 per 13,762 = .0021 or 2.1 incidents per 1,000 wells); blowouts during development drilling in deep gas reservoirs (11 per 22,833 =

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.0005 or .5 incidents per 1,000 wells). Taking the average of these incidence rates results in 1.2 blowouts per 1,000 wells drilled.

Table 14: Offshore gas well blowout rates for different phases of operations.

Operation Category Well Type No. of Wells/Incidents

Exploration Drilling, shallow gas

Number of Exploration Wells Drilled Appraisal 6,257 Wells

Wildcat 7,505 Wells

Blowout (surface flow)

Appraisal 8

Wildcat 14

Blowout (underground flow)

Appraisal 0

Wildcat 0

Diverted well release

Appraisal 2

Wildcat 7

Well release Appraisal 2

Wildcat 2

Development Drilling, shallow gas

Number of Development Wells Drilled

- 22,833 Wells

Blowout (surface flow) - 22

Blowout (underground flow) - 1

Diverted well release - 16

Well release - 2

Exploration Drilling, deep

Number of Exploration Wells Drilled Appraisal 6,257 Wells

Wildcat 7,505 Wells

Blowout (surface flow) Appraisal 9

Wildcat 13

Blowout (underground flow) Appraisal 0

Wildcat 7

Diverted well release Appraisal 01

Wildcat 01

Well release

Appraisal 3

Wildcat 3

Development Drilling, deep

Number of Development Wells Drilled

22,833 Wells




Well release - 5

Completion

Number of Completions 20,328 Wells




Well release - 0

Production

Number of Well Years in Service 211,142 Well Years




Well release - 2

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Workover

Number of Workovers 19,920 Workovers




Well release - 17

Risk Assessment

Risks from Combustion Sources

Diesel exhaust (DE) is one of the largest U.S. sources of fine particulate matter and also contains ozone-forming nitrogen oxides and toxic air pollutants (”Diesel Engine Exhaust”). DE has been classified by EPA as having chronic non-cancer (exacerbates asthma and other respiratory conditions, neurological effects, growth and survival) and carcinogenic (lung cancer, mutagenic/chromosomal) effects from inhalation (U.S. EPA 2003). However, little information is available regarding overall exposures and environmental or human health effects of combustion emissions specifically during UGWD drilling-related activities. Modeling studies conducted by the state of New York on the drilling equipment show exceedances of the 1-hour NOx and PM2.5 standards at 120 and 150-meters away from the well pad, respectively (NYSDEC, 2011). Using Tier II or greater DE engines would help address PM exceedances (NYSDEC, 2011, p. 6-144), while use of particulate traps and selective catalytic reduction technology would help address NOx emissions. Neither of these practices has been specifically recommended in Maryland and it is currently unclear whether the federal Clean Air Act preempts Maryland from doing so. The setback requirements proposed in Maryland are, at minimum, 2-times greater than the distance at which exceedances were modeled in New York and are expected to be effective mitigation for drilling rig emissions. Uncertainty for potential health risks in terms of combustion emissions results from the high volume of vehicle traffic necessary to transport fresh water and other equipment to the site during the drilling phase and prior to hydraulic fracturing. Maryland’s calculation of vehicle traffic, modified from NY’s analysis, estimated 1889 truck trips (1283 heavy trucks, 606 light trucks) per single well and 10,194 (7,118 heavy trucks, 3,076 light trucks) per 6-well pad. Scaling this up to the 150 and 450 well scenarios results in anywhere from approximately 25,000 to 76,000 truck trips per year. Diesel trucks are regulated under Title I of the Clean Air Act, which is a technology-based program that is expected to control emissions over a longer period of time as new equipment is phased in. As a result, older, higher emissions vehicles may still be in industry fleets. Minimizing diesel idling to less than 5 minutes can help reduce emissions, but this is not practicably enforceable and may be counter to the behavior of many operators who are in the habit of leaving engines idle to prevent difficulty with engine restarting, particularly in cold weather. Maryland’s proposed setback distances are calculated from the well pad and may not effectively mitigate human exposure to air emissions from off-site vehicles. Overall due to both drill rigs and the high number of trucks used to deliver supplies/equipment, there is a high probability of combustion emissions in both scenarios. Modeling results presented by NY show Tier 1 drill rig combustions exceeding criteria pollutant concentrations up to 150-meters away and no exceedances if drill rigs are Tier II. With Maryland proposing 1,000-foot well pad setbacks from property boundaries and from occupied dwellings, at least a 2,000 -foot setbacks from private wells, current CAA regulations, and considering the relatively short duration of the drilling phase, the consequences of these drill rig emissions are expected to be minor. CAA regulations for mobile sources are implemented as new equipment/vehicles are purchased and as vehicle fleets modernize. However, because no existing fleet inventory is available to quantify emissions associated with mobile sources and no modeling has been completed for Maryland’s scenarios, there is currently insufficient information (i.e., fleet composition and associated emissions controls) regarding combustion emissions from truck traffic to assess consequences (Table 15).

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Risks from Non-Combustion Sources

The air risks from non-combustion sources include methane and associated hydrocarbon release during drilling and mud/gas separation, dust generated from vehicle traffic on unpaved roads, as well as the rarer instances of well blow-outs. Increased risks for global warming resulting from methane release during drilling activities is a larger national energy policy issue and is discussed separately in the greenhouse gases section. Overall, however, the probability of noncombustion emissions during drilling are considered moderate as they would be likely to occur with air drilling when no drilling fluid is available to help contain fugitive gas as well as with drilling muds where gas may be entrained and released directly to the atmosphere from mud pits. With setbacks and the likelihood of dry gas with little associated natural gas liquids, the probability of VOC emissions or other compounds associated with methane are anticipated to pose only minor health risks during the drilling phase. The greatest probability of non-combustion air emissions are anticipated as a result of dust/particulate matter generated from heavy vehicle traffic on unpaved roads. As shown above, annual truck trips are estimated to be anywhere from 25,000 to 76,000. Since access roads are likely to be unpaved, this high volume of truck traffic will generate fugitive dust and particulates. Vehicle traffic-generated dust is noted in some studies as an impact (Adgate et al., 2014), but no studies were found that measured or otherwise quantified increases in dust levels. Dust control BMPs proposed by Maryland are considered guidelines, are discretionary/not prescriptive, and consequently difficult to enforce. As mentioned above, setbacks were not created to address emissions from vehicle traffic away from access roads. Proposed particulate air monitoring may help determine when traffic-generated dust requires additional control.

Risk from Accidents

As indicated above in Table 14, well blowouts during drilling are relatively rare (approximately 1 in 1,000) and typically pose the greatest risk to workers on site. Maryland’s requirement for blow-out preventers that are designed to withstand up to 1.2 times the maximum expected well pressure will help prevent well blow-outs from occurring. In addition, the proposed 1,000-foot setbacks from occupied buildings, and the setback of at least 2,000 feet from private wells will further reduce risks to off-site citizens. No instances were found in current literature of off-site citizens being killed or injured from well blowouts. The greatest risk of well blow-outs is to onsite workers and worker safety is not regulated by the Departments. As a result, risks to on-site workers are considered outside the scope of this assessment and were not evaluated. Overall the probability of well blow-outs is considered low due to both a low frequency of occurrence and application of Maryland’s proposed BMPs. Since proposed setbacks are expected to be very effective in protecting off-site citizens from blow-outs, consequences are rated as minor.

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Table 15: Risk Assessment for Phase 3 – Drilling.

*Global warming risk of methane not assessed (see Greenhouse Gases section)

Scenario Duration Estimated Number of Emissions Sources/Loads

Emissions Type Pollutants of Concern


Scenarios 1 and 2 30 weeks 15-45 large and small drill rig with compressors

Combustion NOx, benzene, PM Human (Inhalation)

High Minor Moderate

Non-combustion VOCs/Natural Gas Liquids, methane*

Human (Inhalation)

Moderate Minor Low

1 well blowout per 1,000 wells

Accidents/Spills N/A Human (Explosion)

Low Minor Low

3-8 Separators and tanks to hold drilling muds.

Non-combustion VOCs/Natural Gas Liquids, methane*

Human (Inhalation)

Moderate Minor Low

25,000 – 76,000 truck trips per year.

Combustion NOx, PM, benzene Human (Inhalation, Ozone formation)

High Insufficient data Insufficient data

Noncombustion Dust/PM Human (Inhalation)

High Insufficient Data Insufficient data

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Phase 4: Hydraulic Fracturing/Completion


During hydraulic fracturing, the horizontal section of the well is perforated by a series of explosive charges that create small fractures in the target formation in preparation for hydraulic fracturing. Then millions of gallons of water, added chemicals and sand proppant are pumped down the well at high pressure to further fracture the shale. As the fracking water penetrates and enlarges the initial fractures created by the explosive charges, the included proppant (usually silica) fills the interstitial spaces of the created fractures and keeps them propped open so that produced gas can flow into the well. Approximately 14-15 diesel-powered hydraulic fracture pumps (are used on site to pressurize the hydraulic fracking fluid (NYSDEC, 2011).

Figure 6: Hydraulic Fracturing Pumps (Photo courtesy of http://www.jjbodies.com)

Once fracturing is complete, some of the injected fracturing fluids return to the surface as flowback. During the flowback period both hydraulic fracturing fluids and other naturally occurring materials contained in the formation (salts, metals, potentially naturally occurring radioactive materials, natural gas liquids) migrate back to the surface as a result of overlying geological pressure. The flowback is routed to storage tanks on site which have vents that can emit volatile organic compounds to the atmosphere ( Figure 7). The portion of Maryland underlain by the Marcellus Shale (Figure 1) is expected to consist mostly of dry gas with few hydrocarbon liquids. However, hydrocarbon liquids may be present and can consist of commercially valuable liquids (ethane, propane, butane, and pentanes), inert gases (water vapor, helium, and nitrogen), greenhouse gases (carbon dioxide), and compounds with known human health effects (hydrogen sulfide formaldehyde, and benzene, toluene, ethylbenzene and toluene –BTEX) (McKenzie et al., 2012; “Oil and Natural Gas Air Pollution standards”; “Natural Gas-From Wellhead to Burner Tip”).

http://www.jjbodies.com/

http://www.jjbodies.com/ajax_gallery.php?id=34

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Figure 7: Flowback Tanks (Photo courtesy of the Colorado Oil and Gas Conservation Commission)

Natural gas also begins to flow to the surface with the flowback liquids. Natural gas produced at this stage may be temporarily vented to the atmosphere and then ignited by a flare (for testing purposes to determine well pressure, flow and composition (Ohio EPA, 2012). These processes result in combustion and noncombustion air pollution emissions. In some cases if natural gas flow is insufficient, refracturing can occur soon after the initial fracturing to stimulate well production (NYSDEC, 2011, p. 5-98). Refracturing can also occur years later when natural gas production falls below desirable levels.

Emission Sources

Combustion Sources Pumps for injecting hydraulic fracturing fluid – 15 fracturing pump engines total assumed in NY at 2,333 hp each. (NYSDEC, 2011, p. 6-101) Flares (McKenzie et al., 2012) On and off-road vehicle activity. (NY DEC, 2011 , p. 6-115; Leidos, 2014a)

Figure 8: Flares (Photo courtesy of Ohio EPA)

Non-Combustion Sources Venting/emissions from flowback and storage tanks (Alvarez &Paranhos, 2012) Silica emissions when proppant is mixed with fracking water and chemicals. (Adgate, 2014) Accidents Well blowouts

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Duration

Hydraulic Fracturing 5 days per well for the actual fracking - 2 days to mobilize and demobilize fracking equipment. (ALL Consulting, 2010) Scenario 1: At 150 wells, an average of 15 wells/year = 75 days/yr of fracking Scenario 2: At 450 wells, an average of 45 wells/year = 225 days/yr of fracking Flowback: 3-10 days (Avg. 6.5 days, U.S. EPA, 2012) Scenario 1: At 150 wells, an average of 15 wells/year = 98 days/yr of flowback Scenario 2: At 450 wells, an average of 45 wells/year = 293 days/yr of flowback Venting/Flaring – 1 day to several weeks (U.S. EPA, 2011) and completely or partially overlaps with the flowback phase.

Scope

Flowback volume is estimated at 30 percent of the average volume of hydraulic fracturing fluid injected into the well, or 1.5 million gallons of fluid that may contain volatile organic compounds and other contaminants. The truck trips per well to transport equipment and remove flowback discharge, modified from New York (NYSDEC, 2011), are estimated below at 655 truck trips (520 heavy trucks, 135 light trucks) per single well. To scale up to the estimated 6 wells per pad results in a total of 2,645 trips (2,195 heavy trucks, 450 light trucks) per 6-well pad, although this is likely a high estimate as flowback water may be recycled. In addition to the truck trips, there are approximately 15 hydraulic fracturing pumps used for each well. A typical flowback tank holds 21,000-gallons (“Frac Tanks”) of flowback resulting in approximately 72 tanks per pad (1.5 million gallons divided by 21,000 gallons/tank). Table 16: and Table 17 below display well pad activity with both scenarios:

Table 16: Well Pad Activity with 1 Well on 1 Pad



Hydraulic fracturing equipment (trucks & tanks) 175

Produced water disposal 300**

Final pad prep 45 50

Miscellaneous 0 85

TOTAL truck trips per well (1 well on 1 pad) 520 135

Table 17: Well Pad Activity with 6 Wells on 1 Pad



Hydraulic fracturing equipment (trucks & tanks) 350

Produced water disposal 1800**

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Miscellaneous 0 400

TOTAL truck trips per well (6 wells on 1 pad) 2195 450

Scenario 1: 150 wells over ten years results in an average of 15 wells/year. There will likely be simultaneous emissions from well completions at different pads at the same time, although the pads may be separated by a considerable distance. It is assumed these wells are on multi-well pads for total truck trips of 6,613 (2,645 trips X 2.5 well pads) per year. Furthermore, 225 hydraulic fracturing pumps will be in use annually to stimulate 15 wells (15 wells x 15 frac pumps/well) and those 15 wells could amount to 15 separate flaring events. In terms of frac tanks, there will be approximately 180 (72 tanks/pad x 2.5 pads) in use each year. Scenario 2: 450 wells over ten years results in an average of 45 wells/year. There will likely be simultaneous emissions from well completions at different pads at the same time, although the pads may be separated by a considerable distance. It is assumed these wells are on multi-well pads for total truck trips of 19,838 (2,645 trips X 7.5 well pads) per year. Furthermore, 675 frac pumps will be in use annually to stimulate 45 wells (45 wells x 15 frac pumps/well) and those 45 wells could amount to 45 separate flaring events. In terms of frac tanks, there will be approximately 540 (72 tanks/pad x 7.5 pads) in use each year.


Of all the UGWD steps considered for this risk assessment, the hydraulic fracturing step has likely elicited the greatest public concern, mostly due to undisclosed chemicals pumped into the ground during fracking and the potential for methane migration into groundwater as a result casing/cementing failures. However, the health effects of air emission are receiving increased attention. Review of the most recent reports (“Big Oil, Bad Air: Fracking the Eagle Ford Shale of South Texas”) and studies (McKenzie et al., 2012; Field et al., 2014; Adgate et al., 2014; Eapi et al., 2014) conclude that UGWD air emissions create a potential for increased public health risks. They also highlight the scientific community’s need for additional monitoring to better characterize exposures. Applicability of these current studies in Colorado and Texas to the Marcellus in Maryland is complicated by geological differences between formations and differences in the current or proposed regulatory frameworks. Summaries of key air quality findings from the scientific literature are presented below and categorized under criteria or non-criteria pollutants.

Criteria Pollutants

Particulate Matter Modeling exercises performed by the State of NY (NYSDEC, 2011) and the University of Michigan (Rodriguez& Ouyang, 2013) identified substantial particulate emissions from hydraulic fracturing pumps. New York’s modeling found that hydraulic fracturing pumps meeting Tier II emission standards would still exceed both PM2.5 and PM10 standards (NYSDEC 2011, p. 6-143 and 144)) up to 150 meters and 60 meters away, respectively. The University of Michigan’s analysis found that in both the Eagle Ford and Marcellus Shales, hydraulic fracturing pumps were responsible for more than 83 percent of the total combustion emissions associated with Hydraulic fracturing operations. Studies by the University of West Virginia School of Public Health for the WV Dept. of Environmental Protection (McCawley, 2013) also found particulate pollution levels from some well pads exceeding ambient air quality standards at a 625 foot set-back distance from the center of the well pad. Another study by the National Energy Technology Laboratories mobile air monitoring lab found significant increases in PM10 during hydraulic fracturing (Pekney, 2013). Esswein et al. (2013) found worker exposure to silica proppants exceeding occupational health criteria at all sites monitored. Some of these sites had greater than 10-fold exceedances. Although worker exposure is outside the scope of this RA this study indicates silica emissions are occurring and could be transported off-site.

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NOx The NETL study (Pekney, 2013) mentioned above found NOx peaks of 140-160 ppb on the well pad during hydraulic fracturing. Ozone Studies in Colorado (Pétron et al., 2012; Gilman et al., 2013), Texas, and Oklahoma (Katzenstein, 2003) have attributed increased ozone in nearby urban areas to emissions from UGWD activities. Another study (Kemball-Cook, 2010) in the Haynesville Shale region of East Texas and Louisiana projected ground level ozone concentration increases of up to 9 and 17 ppb under different emissions scenarios. Field et al. 2013 found methane and VOC concentrations from UGWD contributing to winter ozone exceedances in Sublette Co., Wyoming.

Non-criteria Pollutants

Benzene and Other Volatile Organic Compounds The WVDEP found benzene concentrations during fracturing/flowback at some drilling sites in WV to be above minimum risk levels established by the Centers for Disease Control and that all sites monitored had detectable levels of Benzene, Toluene, Ethylbenzene and Xylenes (BTEX compounds) at 625 feet from the center of the well pad (McCawley, 2013). McKenzie et al. (2012) found that VOCs, including hydrocarbons, were higher near well pads than in residential areas, higher for residents within a half mile of the well pad than those farther, and were highest during well completion periods. The McKenzie study was conducted at sites that had uncontrolled flowback and also included the influence of diesel engines. Adgate et al. 2014 found other risk assessments confirming the McKenzie study conclusions with elevated lifetime cancer risks driven by benzene, some indication of acute or subchronic noncancer risks for those living closest to well sites, and little indication of chronic noncancer risks. Pilot studies in Colorado (CDPHE, 2010), Pennsylvania’s Marcellus (PADEP, 2010) and Texas’s Barnett Shale (Zielinska et al., 2011; TCEQ, 2012) indicate that VOCs (including benzene and formaldehyde) are emitted during well completions. EPA also recognizes the oil and gas industry is a significant source of VOCs during the well completion phase and has issued new rules to address this source (U.S. EPA, 2012). Coons and Walker 2008 found that benzene emissions from uncontrolled flowback posed the highest cancer and non-cancer risks to human health. Hydrogen Sulfide and Methane Significant health effects with hydrogen sulfide exposure occur at 100 parts per million (ppm) with lethal concentrations at approximately 1,000 ppm (Guidotti, 2010). New York State’s (NYSDEC, 2011) modeling analysis of hydrogen sulfide was projected to violate the state standard (.01 ppm in any 1-hour period) without controls on well stack heights. In a self-survey of residents near UGWD activities in Pennsylvania, 81 percent of respondents reported odors (Steinzor et al. 2013) which are potentially due to hydrogen sulfide because it has a low odor threshold (>4.7 ppm, Eapi et al., 2014). Initial studies show (Eapi et al., 2014) that hydrogen sulfide concentrations can vary from site to site, but overall find no significant differences in concentration between wet and dry gas sites. This study also found hydrogen sulfide concentrations exceeding 4.7 ppm just beyond the fence line in 8 percent of lease sites, and a maximum measured concentration of 137 ppm. These concentrations are above a nuisance/odor threshold but not above concentrations expected to produce human health impacts for off-site (i.e., non-worker) populations. Methane emissions also occur during flowback. Recent studies (Allen et al., 2013) indicate that methane emissions during flowback may be lower than current EPA estimates because of the use of capture equipment on site.

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Other

Colburn (2014) measured other constituents (methylene chloride spikes up to 1730 parts per billion and summed composite polycyclic aromatic hydrocarbons (PAHs) at 15.5. nanograms per cubic meter, ng/m3) in air samples near UGWD operations. Cognitive impacts (lower mental development scores and IQs) from prenatal exposures of PAHs have been found at level from 2-4 ng/m3 and methylene chloride has been identified by EPA [“Methylene Chloride (Dichloromethane)”] as a probable human carcinogen. Colburn cited the source of methylene chloride as solvents used on-site for equipment cleaning purposes.

Risk Assessment


The probability of air risks from combustion sources is considered high in both scenarios as a result of combustion emissions from the large number of high horsepower/emissions hydraulic fracturing pumps used at each well site. University of Michigan studies indicate that hydraulic fracturing pumps account for greater than 80 percent of the emissions from UGWD. As to the consequences of these emissions, New York’s modeling analysis showed Tier II hydraulic fracturing pumps still exceeding PM standard up to 150-meters away. Maryland’s proposed 1,000-foot well pad setbacks from property boundaries and occupied buildings and minimum setback of 2,000 feet from private wells will help locate these emissions away from human receptors The CAA pre-empts Maryland from imposing emission standards on nonroad mobile engines that operate on a site for less than 12 months. Considering the BMPs, as well as the scope and duration of the hydraulic fracturing/completion phase, the consequences of air emissions from the hydraulic fracturing pumps are as follows: scenario 1 combustion emissions (Table 18) occur from 225 hydraulic fracture pumps operating over an estimated period of 75-days and are thus considered of minor consequence due to short duration and proposed BMPs; scenario 2 combustion emissions (Table 19) are expected to occur from 675 hydraulic fracture pumps for the better part of a year (i.e., 225-days) and thus of potentially moderate consequence given the duration, high fracture pump emissions rates even with CAA controls, and a higher potential for localized or temporary impacts. Due to the lower number of trucks used in this phase, the probability of emissions are considered moderate. There is currently insufficient modeling or fleet composition data to determine the consequences of vehicle emissions impacts. Consequences of dust/PM emissions from vehicle traffic are considered minor due to the relatively low volume of traffic during this phase. There are also expected to be flaring emissions. Maryland’s proposed BMPs prohibit flaring during well completion except if the content of flammable gas is very low, or when flaring is required for safety, limit flaring to no more than 30-days during the life of the well and require 98 percent combustion efficiency. Since studies indicate that combustion efficiencies are closer to 70 percent to as low as 15 percent in high wind situations and a 30-day maximum may be hard to enforce, flaring emissions are expected be of moderate probability. However, no studies were found to indicate flaring alone has anything more than minor consequences.

Risks from Noncombustion Sources

The literature review for this phase of UGWD identifies a high probability of noncombustion emissions during flowback, both from the well itself and tanks used to capture flowback water, as well as from the silica proppant during handling/mixing with hydraulic fracturing fluids. Although Maryland is expected to have dry gas, emissions from associated natural gas liquids may occur. It is possible that hydrogen sulfide gas may also be encountered with methane and New York’s modeling efforts indicated potential exceedances of a state-specific standard that was mitigated by increasing stack heights or setbacks. The Departments are proposing to require reduced emissions completions (RECs) on all wells. In its Background Supplemental Technical Support Document for the Final New Source Performance Standards, (EPA, 2012). EPA estimated that REC could reduce the amount of VOCs released during hydraulic gas well completion by 95%. In a recent draft

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whitepaper, EPA stated “Based on the results reported by four different Natural Gas STAR Partners who performed RECs primarily at natural gas wells, a representative control efficiency of 90% for RECs was estimated.” Oil and Natural Gas Sector Hydraulically Fractured Oil Well Completions and Associated Gas during Ongoing Production (EPA, 2014). Direct measurements of methane emissions at 27 well completion flowbacks found that “net or measured emissions for the total of all 27 completions are 98% less than potential emissions.” (Allen et al., 2013; PNAS, 2013). EPA recently issued emissions regulations on tanks that emit more than 6 tons of VOCs and Maryland is requiring these for all tanks upon startup. The New Source Performance Standard requires that VOC emissions from those storage tanks be reduced by 95% (40 CFR 60.5395). For purposes of this risk assessment, we are assuming that the recommended BMPs are followed; we acknowledge, however that the estimated efficiencies may not be achieved in all cases in the field and that the reduction efficiencies cited above have only been independently verified by one study using a limited dataset. Lastly, the setbacks will help minimize human exposures to all non-combustion emissions except those associated with vehicles. Considering these proposed BMPs, the scope and duration of the hydraulic fracturing/completion phase, and potential for health effects identified in current literature from release of hazardous air pollutants during flowback, consequences are considered minor for scenario 1 (Table 18) but moderate under scenario 2 (Table 19), mainly as a result of the near year-round duration of scenario 2 noncombustion emissions. Further discussion of methane emissions in the context of global warming are discussed in Cumulative Impacts section below. Regarding silica emissions from proppant handling, consequences for both are also considered minor as the proposed BMPs and setbacks are expected to prevent significant exposures to human receptors off-site.

Risk from Accidents

Using the data in Table 18 and Table 19, provided by the Association of Oil and Gas Producers suggest 4.5 blowouts for every 10,000 wells drilled (9/20,328), resulting in a low probability of occurrence. The greatest risk from blowouts are to workers on site and is thus outside the scope of this risk assessment. The consequences to off-site receptors from a well blowout are considered minor.

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Table 18: Scenario 1 Risk Assessment for Phase 4—Hydraulic Fracturing


Scenario Activity/Duration Annual Estimated Number of Emissions Sources/Loads



Scenario 1 Hydraulic Fracturing during a total of 75 days

225 pumps (2,333 horsepower)

Combustion NOx, PM, benzene Human (Inhalation)

High Minor Moderate

Silica proppant for up to 6 wells/pad

Non-combustion Silica Human (Inhalation)

High Minor Moderate

Flowback during a total of 98 days

15 flaring events Combustion Carbon Dioxide, PM Human (Inhalation)

Moderate Minor Low

180 storage tanks, 15 venting and separation events.

Noncombustion Methane*, hydrogen sulfide, VOCs/Natural Gas Liquids/BTEX

Human (Inhalation)

High Minor Moderate

4.5 blowouts per 10,000 wells


Low Minor Low

Not determined 6,613 truck trips per year.


Moderate Insufficient data Insufficient data


Moderate Minor Low

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Table 19: Scenario 2 Risk Assessment for Phase 4—Hydraulic Fracturing





Scenario 2 Hydraulic Fracturing during a total of 225 days

675 pumps (2,333 horsepower)


High Moderate High

Silica proppant for up to 6 wells/pad

Non-combustion Silica Human (Inhalation)

High Minor Moderate

Flowback during a total of 293 days

45 flaring events Combustion Carbon Dioxide, PM Human (Inhalation)

Moderate Minor Low

540 storage tanks, 45 venting and separation events.

Noncombustion Methane*, hydrogen sulfide, VOCs/Natural Gas Liquids/BTEX

Human (Inhalation)

High Moderate High



Low Minor Low

Not determined 9,825 truck trips per year.





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Phases 5 and 6: Production/Processing and Ancillary Infrastructure


Pipeline systems are installed during this phase to connect wells to transmission lines. Prior to installation, pipes are delivered via trucks and are installed underground using ditch-diggers and other construction equipment. After installation, pipes can leak methane over time. Pipes can also be inadvertently ruptured during other construction-related activities creating an explosion/safety hazard. Compressors ( Figure 9) may be necessary on site to provide proper gas pressurization and flow through pipelines. Offsite compressors are also required to maintain necessary pressures to deliver gas to a processing plant or transmission line. Internal combustion engines are typically used at gas gathering, boosting and compression and can be powered by raw or processed natural gas as well as by diesel fuel or gasoline.

Figure 9: On-Site Gas Compressor Station (Photo courtesy of the Colorado Oil and Gas Conservation Commission)

Periodic purging of liquids, referred to as unloading, is necessary to clear the well of any liquids that hinder flow of gas. Unloading can result in emissions of methane and any other constituents associated with the produced gas. In addition, produced gas may need additional processing to prevent condensation/crystallization of liquid compounds in the gas gathering lines. This processing may occur both on-site, known as field processing (Figure 10), and off-site at centralized processing plants. On-site heaters, oil/water/gas separators and dehydrators may be necessary before gas can enter a gathering line. Although the portion of the Marcellus in Maryland is expected to be mostly dry gas needing minimal, if any, processing, there may still be well to well variability in gas composition that makes some field processing necessary.

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Figure 10: Field Processing of Natural Gas (Photo courtesy of the Colorado Oil and Gas Conservation Commission)

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Figure 11: The Natural Gas Production Industry (Photo courtesy of EPA “Oil and Natural Gas Air Pollution Standards”)

Emission Sources

For the purposes of this risk assessment, sources considered are limited to the well pad, an off-site compressor, and on-site gas gathering lines. Combustion Sources On and Off-site compressors Non-Combustion Sources Equipment leaks from pneumatic valves, pumps, flanges, gauges, and pipe connectors. (Alvarez & Paranhos, 2012) On-site oil/water/NGL separator, dehydrator, and condensate storage tanks. (NYSDEC, 2011) Well unloading (Allen et al., 2013) Accidents/Spills Well blowouts

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Activity duration and Scope

Duration

Production declines over time, but each well is assumed to produce for 20 years or more. Some level of refracturing may also occur, extending the life of individual wells, but is not considered here.

Scope

One on-site and one off-site compressor per pad and one line heater (NYSDEC, 2011) operating over 10 years. Well pads may also have dehydrators, separators and condensate tanks to store NGLs, although the Maryland portion of the Marcellus is likely to be dry gas with little or no natural gas liquids. Well unloading in the Allen et al., 2013 study happened on avg. 6 times/year while the American Petroleum Institute/American Natural Gas Alliance survey EPA calculated an average unloading rate of 32.57 times/year. Scenario 1: Peak combustion emissions from 50 compressors (1 on and 1 off-site multiplied by 25 pads) running simultaneously in Year 10. Peak well unloadings ranging from 900 – 4,886 (150 wells multiplied by 6 and 32.57 unloadings, respectively) in year 10 resulting in noncombustion emissions. Unquantified noncombustion emissions from site processing, condensate storage tanks and pipe leakage. Assume 825 (33 trips times 25 well pads) peak light truck trips/year for well unloading, to perform leak detection/repair, monitoring, and general site maintenance. Scenario 2: Peak combustion emissions from 150 compressors (1 on and 1 off-site multiplied by 75 pads) running simultaneously in Year 10. Peak well unloadings ranging from 2,700 – 14,657 (450 wells multiplied by 6 and 32.57 unloadings, respectively) in year 10 resulting in noncombustion emissions. Unquantified noncombustion emissions from site processing, condensate storage tanks and pipe leakage. Truck trips at this stage are assumed to be predominately light trucks of relatively small number compared to the other phases. Assume 2,475 (33 trips times 75 well pads) peak light truck trips/year for well unloading, to perform leak detection/repair, monitoring, and general site maintenance.


Criteria Air Pollutants

Combustion Emissions In calculating criteria pollutant emissions associated with on and off-site compressors at a well pad, NY assumed a 2,500 hp on-site compressor running year-round resulting in 48.3 tpy NOx (NYSDEC, 2011, p. 6-101) and an off-site compressor with a 1,775-hp Caterpillar G3606 engine (NYSDEC, 2011, p. 6-107). NY modeling results did not project compressor noncompliance with ambient air standards for criteria pollutants.

Non-Criteria Pollutants

Combustion Emissions NY estimated total VOCs and HAPs associated with off-site compressors to be 5 and 2.7 tons/year, respectively. They also modeled exceedances of their state-specific standard (i.e., annual guideline concentration or AGC) for formaldehyde emissions resulting from the off-site compressor. NY concluded that, in addition to required NESHAP controls required for compressors, limiting public access to at least 150-meters from the compressor would address remaining exceedances.

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Non-Combustion Emissions

NY modeled exceedances of their AGC for benzene as a result of glycol dehydrators (NYSDEC, 2011, 6-140). EPA cites glycol dehydrators as the primary source of emissions at oil and gas production facilities, though downstream infrastructure is not assessed here (“Outdoor Air-Industry, Business, and Home: Oil and Natural Gas Production- Additional Information”). New York also noted that in cases where wet gas is encountered, there will be potential emissions of VOCs and HAPs (e.g., benzene) from condensate storage tanks. Coons and Walker 2008 modeled both cancer and non-cancer benzene exceedances resulting from uncontrolled emissions from glycol dehydration units and condensate tanks, but this study was done in Colorado where more wet gas is encountered. As detailed above in the hydraulic fracturing/completion step, the portion of the Marcellus underlying Maryland is comprised of the eastern-most portion of the play comprised of mostly dry gas. New York’s SGEIS likewise anticipated mostly dry gas with little natural gas liquids. As a result, non-combustion emissions (BTEX or VOCs) are not expected to result from natural gas liquids and associated processing/production (NYSDEC, 2011, p. 6-105). Allen et al. (2013) measured methane emissions resulting from equipment leaks during well production as well as during well unloading events. Overall, measured emissions from the study (957 gigagrams (Gg) methane ± 200 Gg) were found to be comparable to EPA’s national emissions estimates (~1,200 Gg methane). This work focused specifically on leaks from pneumatic controllers/pumps as well as leaks from equipment, pipes, and fittings. Even though overall emissions estimates from this study were found to be similar to current national estimates, emission rates from specific equipment evaluated in the study varied significantly. For example, the study found that methane emissions from intermittent and low bleed pneumatic devices are anywhere from 29 percent to 270 percent higher than national emissions estimates. The study also found that the average number of well unloadings calculated from the 9 wells sampled (approximately 6 well unloadings/year) is much lower than averages from other studies, (approximately 32 unloadings/year)( API/ ANGA, 2012). The Allen study is important as it is one of the first studies of actual on-site emissions collected independently of industry derived estimates. The population of evaluated sites (150 production, 27 completion, 4 workover, and 9 unloadings sites), however, is limited in number and the sites were not randomly chosen. The wells were in different regions and, even within the same region, results varied due to differences in control equipment and natural gas composition. Also, some emissions sources, such as on-site tanks, were not evaluated during the course of study.

Risk Assessment


The probability of air risks from combustion sources is considered high in both scenarios as a result of combustion emissions from on and off-site compressors running year round for the assumed 20-year life of each well and light truck trips associated with well pad site visits. As to the consequences of compressor emissions, New York’s modeling analysis from a single well pad that included one drilling and one off-site compressor indicated exceedance of their state-specific formaldehyde standard that was mitigated with a 150-meter setback. New York’s modeling of only a single off-site compressor likely underestimates compressor emissions because Department staff observed up to 5 large compressors operating 24-hours a day at an off-site compressor station in West Virginia. New York’s modeling was done before the new performance standards for compressors were promulgated. Maryland’s proposed 1,000-foot setbacks of compressors from occupied buildings help locate compressors away from human receptors but data validating this setback distance are not available. Maryland is also considering emissions standards for equipment used on the well pad, but current CAA regulations pre-empt Maryland from implementation. If compressors are run on natural gas produced at the well pad, combustion emissions will be reduced. The comprehensive gas

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development plan (CDGP) will help locate compressor sites in the least impactful areas, but will not necessarily ensure coordination between companies in compressor locations. On the consequences side, both scenarios result in simultaneous year-round combustion emissions from multiple well pads that build to a peak in year 10 before declining arithmetically to zero in year 20. Furthermore, uncertainty remains in terms of specific compressor locations, numbers, and fuel sources to confidently assign consequences. Conducting modeling analysis during CDGP development could further help minimize impacts from compressor combustion emissions. However, insufficient information exists at this time to determine overall consequences of compressor emissions for either scenario (Table 20). The consequences of combustion emissions from light trucks are considered minor in light of the relatively small number of vehicles, that they are light-duty (i.e., non-diesel), and have existing CAA controls.

Risks from Noncombustion Sources

The literature review for this phase of UGWD identifies a high probability of noncombustion emissions for both scenarios, mainly associated with emissions during well unloading and from equipment leaks from compressors, pneumatic valves, pumps, gauges and pipe fittings. In terms of assessing consequences, Maryland is expected to have dry gas with fewer natural gas liquids emitting BTEX or other harmful compounds. Where processing is necessary, Maryland’s implementation of BAT is expected to minimize emissions of public health concern. It is possible that hydrogen sulfide gas may also be leaked but Maryland’s setbacks are anticipated to mitigate any associated risks. Maryland is proposing leak detection and repair programs that should also help mitigate risks as long as they can be effectively enforced. Maryland is also requiring BAT systems for well unloading which are anticipated to have 70 percent emissions reduction efficiency. Finally, Maryland is proposing a requirement for methane emissions offsets that, in addition to the above BMPs, is expected to address methane emissions and associated risks. Discussion of methane emissions in the context of global warming potential are covered in Cumulative Impacts section below. Considering these BMPs, and that few NGLs with potentially harmful pollutants are expected and/or of short duration, minor consequences are anticipated for noncombustion emissions. The greatest likelihood is for methane leaks that are not expected to pose a public health threat and which are discussed further in the greenhouse gas section below.

Risk from Accidents

Using the data in Table provided by the Association of Oil and Gas Producers suggests 4 blowouts for every 100,000 wells in production (8 per 211,142), resulting in a low probability of occurrence. The greatest risk from blowouts are to workers on site and is thus outside the scope of this risk assessment. The consequence to off-site receptors from a well blowout is considered minor.

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Table 20: Risk Assessment for Phases 5 and 6: Production/Processing and Ancillary Infrastructure





Scenarios 1 and 2

20 years (peak emissions in year 10)

50-150 (annual peak) compressors

Combustion NOx, PM, benzene

Human (Inhalation)

High Insufficient data

Insufficient data

25 – 75 (annual peak) well pads with emissions from pipes, valves, fittings, etc.

Noncombustion Methane* Human (Inhalation, explosion)

High Minor Moderate

900 – 14,657 (annual peak) well unloadings

Noncombustion Methane*, hydrogen sulfide, VOCs

Human (Inhalation)

High Minor Moderate



Low Minor Low

825 – 2,475 (annual peak) light truck trips

Combustion NOx, PM, benzene

Human (Inhalation)

High Minor Moderate


High Minor Moderate

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Risk of Cumulative Impacts or Synergistic Effects

The previous discussion divided the UGWD process into phases to help identify specific activities in each phase that have the greatest probability of occurrence and which may also result in the greatest consequences to public or environmental health. This stepwise approach allows the Department to target specific UGWD phases and emissions sources with the highest remaining risks and which may need further BMP controls. It is also necessary to look across all of the UGWD phases in a single view to determine whether there may be risks associated with cumulative impacts or synergistic effects. Air pollution emissions during UGWD are unique compared to other potentially affected environmental media because these emissions occur during every phase of the UGWD process whereas water or land impacts will typically only occur if there is an accident, spill, BMP failure, or illegal disposal of drilling waste. Every single phase of UGWD relies upon internal combustion engines to either power equipment or deliver it to the site and once drilling begins methane itself may be emitted. Some emissions (compressors, productions leaks, condensate tank emissions, vehicles) will occur year-round, while other emission sources (noncombustion emissions during drilling, venting and flowback) are of shorter duration. Nearly all sources emit pollutants known to have human health risks (e.g., benzene) while emissions less problematic from a human health standpoint (e.g., methane) have climate change implications. In addition, certain pollution emissions (nitrogen oxides and VOCs) are already known to combine into constituents (ozone) with harmful health effects. Recent health risk assessments (McKenzie et al., 2012) have identified uncertainty regarding the public health impact of this complex chemical mixture. As a result, there is a high probability of emissions that overlap spatially as well as temporally and which singly, or in combination with other pollutants, have the potential to impact human health. Maryland’s proposed BMPs and setbacks will minimize health and environmental effects, but by how much, under which scenarios and whether residual risks are ultimately acceptable cannot be determined without more rigorous, location-specific monitoring and modeling. New York (NYSDEC, 2011) conducted a limited modeling exercise of emissions on the well pad and made some estimates of on-road vehicle emissions using vehicle miles traveled and number of truck trips from an Industry Information report. On this basis, NY concluded that NOx and VOC emissions would be relatively small and effectively mitigated for in their state implementation plan (SIP). Two important caveats to this modeling are that Maryland estimated twice the truck trips (1,000 per well) during hydraulic fracturing that NY assumed and the NY modeling did not include photochemical ozone formation. New York noted that “regional photochemical air quality modeling is a standard tool used to project the consequences of regional emission strategies for the SIP. The application of these models is very time and resource intensive. For example, these require detailed information on the spatial distribution of the emissions of various species of pollutants from not only New York sources, but from those in neighboring states in order to properly determine impacts of NOx and VOC precursor emissions on regional ozone levels. At present, detailed necessary information for the proper applications of this modeling exercise is lacking.” (NYSDEC, 2011, p. 6-180) Furthermore, impacts associated with dust from heavy vehicle traffic on unpaved roads have not been quantitatively assessed by NY or in the scientific literature. This lack of detailed modeling information coupled with the fact that empirical studies are finding increased ozone levels associated with UQWD sites, some contributing to ambient air standards nonattainment (Field et al., 2013), suggest that more information is needed in Maryland to determine cumulative impacts. Reducing the emissions of VOCs will reduce the possibility of the formation of ground level ozone. Garret County Maryland is currently attaining ambient air quality standards and thus falls under the prevention of significant deterioration part of the federal act. More information will be needed to determine if both significant deterioration of Garrett Co. air quality may occur or if air quality downwind in the Baltimore-Washington region ozone nonattainment may be exacerbated by UGWD.

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Greenhouse Gases

According to the Environmental Protection Agency, the four most important greenhouse gases are carbon dioxide, methane, nitrous oxide, and fluorinated gases. Two of these gases, methane and carbon dioxide, are released during natural gas extraction. Methane is the primary constituent of natural gas and can be released during drilling, hydraulic fracturing, production/processing, and by leaks in pipes and valves. Carbon dioxide is the main component of emissions from internal combustion engines and is released whenever fossil fuels are combusted. Figure 12 below shows EPA estimates on the percent composition of greenhouse gases (GHGs) emitted in the U.S. during 2012.

Figure 12: Composition of Greenhouse Gases in Percentages (Courtesy of EPA (http://www.epa.gov/climatechange/ghgemissions/gases.html)

http://www.epa.gov/climatechange/ghgemissions/gases.html

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According to EPA, methane has 21 times more global warming potential than carbon dioxide over a 100-year timeframe and studies (Alvarez & Paranhos, 2012) have found oil and gas development activities to be the largest U.S. source of methane emissions. Howarth (2012) suggests that when methane contributions from UGWD are considered over a shorter timeframe (20 years), they may be responsible for almost half of the warming impact from current emissions. A recent study by Brandt et al. 2014 reviewed technical literature from the last 20 years on natural gas emissions in the U.S and Canada and concluded: (1) EPA estimates consistently underestimate methane emissions with the oil and gas industry as consistent contributors; (2) a small number of “superemitters” may be responsible large emissions; (3) recent atmospheric studies showing large methane emissions are likely not representative of the oil and gas industry as a whole; and, (4) 100-year impacts from leakage is likely not large enough to outweigh natural gas benefits over coal. In short, the scientific community is still divided on whether GHGs emitted during the production and transmission of natural gas outweigh the lower GHG emissions of natural gas when it is burned and over what timeframe. EPA’s current emissions estimates were developed in the early 1990s and did not consider current extraction levels or UGWD techniques. Maryland’s proposal to require rigorous leak detection systems and methane offset BMPs will help reduce overall emissions. However, to accurately assess whether UGWD creates an overall unacceptable risk to global warming, it will be necessary to empirically measure the life-cycle greenhouse gas emissions from other fuel sources, such as coal and petroleum, for relative comparison. This type of analysis would include analyzing different energy sectors across the country and recalculating life-cycle energy emissions inventories. Since this level of effort is outside the scope of this risk assessment, increased risks to global warming from shale gas extraction in Maryland has not been considered in this analysis.

Conclusions

Looking across the risk assessments for each phase there are several conclusions regarding risks. First and with the exception of the seismic assessment phase, there is a high probability of air pollution emissions during all UGWD phases even with BMPs in place. Secondly, most of these high probability emissions result from multiple, oftentimes overlapping combustion sources that for several sources (mobile sources, hydraulic fracturing pumps, and compressor emissions) have insufficient data or modeling information to reasonably determine consequences. Thirdly, for the two scenarios evaluated (150 and 450 total wells) there is not enough information to assess differences in risk during each UGWD phase. The only exception to this is the hydraulic fracturing/completion phase where both combustion and noncombustion emissions for the 450 well scenario are projected to occur over 60-80 percent of the year, respectively, compared to 20-27 percent of the year for a 150 well scenario. This results in the 450 scenario rated as having moderate consequences compared to minor consequences for a 150 well scenario. These findings are consistent with other recent studies (Field, 2014; McKenzie, 2012) on air emissions impacts which conclude that air emissions from UGWD require further study and that site-specific assessments will be necessary to determine risk. They are also consistent with a recent report (2013) by the Office of the Inspector General on EPA’s emissions estimates for the oil and gas sector which concludes that oil and gas production results in substantial emissions that can impact air quality and that there are currently limited direct emissions measurements. This situation hinders EPA’s ability to quantify air impacts and assess health risks. Emissions rates and associated BMP efficiencies evaluated to date have largely been produced through voluntary industry reporting. As discussed above, only one study (Allen et al., 2013) was found where actual on-pad emissions were measured. However, this is a single study that relied on measurements taken at a limited number of sites and which highlighted significant geographical variability and measurement uncertainty that further emphasizes the need for location-based assessments.

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Given the above conclusions and literature results, the overall probability for air emissions is high while the consequences cannot be determined at this time due to insufficient information on proposed BMP and setback efficiencies, combustion emissions impacts and photochemical transformation, specific location/density of wells/well pads, and potential for cumulative/synergistic effects.

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i

Appendix C

Road and Traffic

Contents

Introduction ............................................................................................................................................................ 1

Number of trips ................................................................................................................................................. 2

Maryland roads .................................................................................................................................................. 5

Road damage .......................................................................................................................................................... 5

Impact of heavy truck traffic on roads............................................................................................................... 5

Traffic ...................................................................................................................................................................... 9

Traffic congestion and community character .................................................................................................... 9

Traffic accidents ............................................................................................................................................... 11

Ecological impacts ................................................................................................................................................ 13

Steps ..................................................................................................................................................................... 14

Site identification ............................................................................................................................................. 15

Site preparation ............................................................................................................................................... 15

Drilling .............................................................................................................................................................. 16

Hydraulic fracturing and well completion ....................................................................................................... 17

Proposed Best Management Practices ................................................................................................................. 19

Fewer trips ....................................................................................................................................................... 20

Transportation planning and road construction .............................................................................................. 20

Road agreements ............................................................................................................................................. 21

Existing tools .................................................................................................................................................... 22

Flowback disposal onto roads not permitted .................................................................................................. 22

Risk Mitigation ...................................................................................................................................................... 23

Road use agreement issues ............................................................................................................................. 23

Compliance ...................................................................................................................................................... 24

Roadway Accidents .......................................................................................................................................... 25

Conclusion ............................................................................................................................................................ 27

Suggestions for Additional Mitigation .................................................................................................................. 32

References ............................................................................................................................................................ 33

1

Introduction

Unconventional Gas Well Development (UGWD) through hydraulic fracturing requires a substantial

amount of truck traffic. Typically, all materials, equipment, water, proppants, petroleum products,

and chemicals are transported via truck to hydraulic fracturing sites (U.S. EPA, 2011, NYSDEC, 2011).

Nearby communities will experience increases in road damage, traffic, noise, air pollution, and road

construction. This section of the risk assessment will address the risks of damage to the existing road

infrastructure, community impacts from increases in traffic, and ecological impacts from road

construction. Sources, consequences, and mitigations of risk will be noted throughout. Other truck

traffic impacts will be covered in the air pollution, noise and visual impacts, and fracking fluid

sections of the report.

In this document, the road damage risk being evaluated is the combination of the probability and

consequence of damage to roads by UGWD trucking. The community consequences of road damage

include repair costs, impeded driving for short- or long-term periods, hindrance of emergency

services, higher risk of rollover of trucks, and damage to residents' vehicles, among other impacts.

Also considered are issues regarding compliance with safety regulations relating to trucks and the

feasibility of recovering the costs of road repair from those responsible.

Next, the traffic risk being evaluated is the combination of the probability and consequence of traffic

accidents and congestion on the community as a result of UGWD trucking. The community

consequences of more truck traffic include injuries and fatalities from crashes, hindrance of

emergency services, impeded driving for short- or long-term periods, change in the character of

rural communities, and local cost increase to control traffic. Regulation of commercial trucks and

truck drivers will also be discussed.

Finally, the ecological risk being evaluated is the combination of the probability and consequence of

road construction and increased traffic on surface water, habitat, wildlife, and recreation. The

consequences include sedimentation and pollution of surface water, forest loss and fragmentation,

harm to fish and wildlife, and outdoor recreation impacts.

2

In the following sections, trucking activity associated with UGWD is examined, followed by a

literature review on road damage and traffic risks. The truck traffic associated with each step of

UGWD process is broken down, and applicable proposed best management practices are

summarized. Finally, examples of issues associated with managing these risks are discussed, and risk

is qualified and quantified where possible.

Number of trips

Damage and traffic risks discussed in this section of the report will be based on estimated numbers

of truck trips provided by ALL Consulting (2010), as prepared for the Independent Oil and Gas

Association of New York (Table 1). This ALL Consulting (2010) report was prepared in response to

information requests from the New York Department of Environmental Conservation during

development of its draft Supplemental Generic Environmental Impact Statement (EIS). MDE made

certain modifications to account for hauling weight limitations and to standardize the numbers to

this risk assessment’s scenarios.

The values in Table 1, below, represent one-way, loaded truck trips estimated for one horizontal

well on one well pad. To include empty truck trips, one can assume doubled values. (Empty trucks

would contribute to traffic but are less likely to cause road damage.) The calculations are based on

the assumption that all water will be delivered via trucks (no pipelines). The hydraulic fracturing of

each well is assumed to require 5 million gallons of water, an amount deemed conservative

(NYSDEC, 2011). Here, the relatively small volume of chemical additives is not assumed to be

included in that total. It was assumed that all flowback and produced water would be removed from

the well site by truck; however, Maryland is proposing to require substantial recycling and reuse of

this water onsite.

Table 1. Estimated number of loaded, one-way truck trips for one well pad with one well.

* Modified from ALL Consulting 2010 to account for 5,000,000 gallons/well and 5,000 gallons/truck. ** Modified from ALL Consulting 2010 to account for 30% flowback volume. Sources: ALL Consulting, 2010; NTCC, 2011; NYSDEC 2011.





Drilling fluids 45 0

Non-rig drilling equipment 45 0



Completion equipment 5 0

3

Hydraulic fracturing equipment (trucks & tanks) 175 0

Hydraulic fracturing water hauling 1000* 0

Hydraulic fracturing sand 23 0

Produced water disposal 300** 0


Miscellaneous 0 85

TOTAL truck trips per well pad (1 well) 1848 831

The original table from All Consulting (2010) listed the value for water hauling trips associated with

hydraulic fracturing as 500 trips. However, delivering 5 million gallons of water in 500 trips would

mean that each truck would carry 10,000 gallons. The weight of this water exceeds the standard

weight limit of 80,000 pounds (COMAR 11.04.01; 23 CFR 658.17):

This conversion is based on freshwater density, and shows weight exceedance even without the

truck’s tare weight. Instead, since high-volume options for water-hauling trucks vary from about

4,000 to 6,000 gallons, 5,000 gallons per truck was used to recalculate the number of water hauling

trips (The Gasaway Co., 2002; J&J Truck Bodies & Trailers, 2008; Ledwell, 2014; Oilmen’s Truck Tanks

2012). One thousand 5,000-gallon truck loads would be required to transport 5 million gallons of

water.

Secondly, the original table assumed that 20% of the fracturing fluid pumped into the well would

return as flowback (100/500 = 0.2). Adjusting this to reflect MDE’s scenario assumption of 30%

flowback results in 300 produced water disposal truck trips.

Finally, Table 2 was scaled to six wells per well pad to be consistent with estimates of the number of

wells per pad in the two scenarios being evaluated. The same scaling factors were used from NTC

Consultants’ (2011) review of NYSDEC’s Generic EIS. Following this approach, Table 2 below

multiplies well-based activities by 6, drill rig activities by 2, and well pad activities by 1. The

Miscellaneous light truck trips’ scaling rationale could not be determined, so NTC’s 8-well scenario

number of 400 was applied to this 6-well scenario.

4

Table 2. Estimated number of loaded, one-way trips per well pad with six horizontal wells.

* Modified from ALL Consulting 2010 to account for 5,000,000 gallons/well and 5,000 gallons/truck. ** Modified from ALL Consulting 2010 to account for 30% flowback volume. Sources: ALL Consulting, 2010; NTC Consultants, 2011; NYSDEC, 2011.

Well pad activity Scaling Coefficient, 6 wells/pad

Early well pad scenario (All water transport by truck)


Drill pad construction 1 45 90

Rig mobilization 2 190 280

Drilling fluids 6 270 0

Non-rig drilling equipment 2 90 0

Drilling (rig crew, etc.) 6 300 840

Completion chemicals 6 120 1956

Completion equipment 2 10 0

Hydraulic fracturing equipment (trucks & tanks) 2 350 0

Hydraulic fracturing water hauling 6 6000* 0

Hydraulic fracturing sand 6 138 0

Produced water disposal 6 1800** 0

Final pad prep 1 45 50

Miscellaneous - 0 400

TOTAL truck trips per well pad (6 wells) 9358 3616

To check the reasonableness of these estimates, applications that had been filed to drill in

Maryland’s Marcellus Shale were reviewed. The values appear in Table 3. However, since the same

values in this table appeared in more than one application despite millions of gallons of variation

among stated water volumes), this is being used here only as a general comparison (Chief Oil & Gas

LLC, 2010, 2011; Enerplus Resources, 2011).

Table 3. Trips generated in UGWD. Sources: Chief Oil & Gas LLC 2010, 2011; Enerplus Resources 2011.

* Does not include work crew trips.

Phase Duration Estimated No. of Round Trips*

Initial Construction (Well pad or freshwater impoundment)

3-4 weeks 20-50

Drilling of Well 6 weeks, most traffic during first 2 weeks

200-400

Water Delivery / Fracturing Shale 4-6 weeks 1000-1500

Completion and Dismantling Site (includes disposal of wastewater)

2 weeks – 2 months 300-500

Reclamation of Site 2-4 weeks 20-40

Gas Generation 15 plus years 1 per 6 months

5

Of note, the number of round trips for water delivery and fracturing listed above (1,000 to 1,500

trips), is closer to MDE’s modified trip number for this step (1,000) than to ALL Consulting’s provided

table (500). Similarly, the above completion and dismantling trips (300 to 500 trips) match MDE’s

modified produced water disposal value (300 trips) which, again, is closer than the value estimated

by ALL Consulting (100 trips). Estimates of truck trips associated with initial construction as well as

final pad preparation/reclamation of site numbers are similar in both tables. Truck trips associated

with drilling, however, are lower in this table (200-400) than in ALL Consulting (sum of 1,970 trips).

Although some values vary, this information provides valuable overall perspective for the magnitude

of truck trips nearby communities can expect should Marcellus Shale UGWD move forward.

Maryland roads

In previously filed UGWD permit applications, the following roads were specified for use by an

applicant (Table 4). This gives some perspective of the possible roadway use to be expected in

Western Maryland. The grade of some of these roads could reduce truck speeds. Drillers will also be

building new access roads which will likely be unpaved.

Table 4. Roads and bridges for two drilling applications submitted to MDE.

Permit application Road or bridge Jurisdiction or weight limit

Chief Oil & Gas LLC 2010, Guard Unit

Friendsville-Addison Road and Maple Street Garrett County roads

MD-42/South Friendsville Road State road

I-68 Federal road

Bridge over Mill Run stream near Mill Run Road, along Friendsville-Addison Road

Single-axle 62,000 lbs; Tandem-axle 80,000 lbs

Bridge over Bear Creek stream in Friendsville, along Friendsville-Addison Road


Bridge over Youghiogheny River in Friendsville, along Friendsville-Addison Road


Chief Oil & Gas LLC 2011, Farmer Unit

Old Morgantown Road West, Blooming Rose Road, and Fearer Road

Garrett County roads

MD-42 State road

US-40 National Pike and I-68 Federal roads

Bridge over Buffalo Run stream near MD-42, along Old Morgantown Road West


Road damage

Impact of heavy truck traffic on roads

Higher truck trip frequency and weight leads to an increased rate of road deterioration. Roads are

designed to sustain the amount and type of traffic projected at the time of construction (Abramzon

6

et al., 2014, NYSDEC, 2011). Design parameters include frequency of trips, weight of vehicles, and

size of vehicles. UGWD operations would be a substantial source of additional truck trips carrying

heavier loads than what many roads are designed to handle, especially smaller roads, shortening the

expected road life.

A little more vehicle weight leads to a lot more road damage, and trucks weigh tens of thousands of

pounds more than cars. The Federal Highway Administration’s review of pavement impact states

that an increase in axle weight increases pavement deterioration exponentially, by approximately a

power of three (FHWA, 2000). This means that, depending on differences such as axle weights and

pavement characteristics, one truck trip can cause as much pavement damage as hundreds to

thousands of car trips (Abramzon et al., 2014; Merriss, 2000, Alaska DOT & Public Facilities, 2004).

Road damage comes in the form of cracking, rutting, failure of the road structure, and potential

damage to traffic control devices and stormwater infrastructure along road sides. Bridges can also

be structurally harmed (NYSDEC, 2011). More axles, shorter spacing of axles, and dual tires on trucks

are key ways to reduce the magnitude of downward force that loads exert on roads (FHWA, 2000).

Though requiring the use of trucks with additional axles allows weight to distribute across a larger

surface area, this does not eliminate road damage. In a study examining the impacts of different

truck configurations on pavement, single- and tandem-axle trucks caused cracking, but additional

axles caused rutting instead (Salama et al., 2006).

Different roadway types will experience different rates of deterioration. Due to their expected

proximity to gas well sites, their smaller size, and their design specifications based on lower traffic

and lighter loads, local roads would be expected to experience the greatest damage. Larger state

roads built to sustain high frequencies of traffic including heavy trucks are generally expected to

adequately support the many truck trips from well development. However, the thousands of

projected heavy truck trips will incrementally deteriorate the roads, shortening pavement life. This

means that state road repair and maintenance dates could come earlier than anticipated, resulting

in additional cost to the state. The gradual nature of this process can make estimating additional

cost and demonstrating causal attribution difficult (NYSDEC, 2011; Mitchell, 2010).

Valuation of road damage

Several case studies have calculated cost estimates associated with road damage from trucking

operations for natural gas well development. Some factors that influence variation in cost estimates

include truck axle configurations, miles driven, pipeline use assumptions, number of wells per pad,

and amount of water, equipment, and materials needed. Characteristics that vary by state include

7

roadway types, reconstruction and maintenance costs, and disposal distances (Abramzon et al.,

2014).

A study focusing on Pennsylvania’s Marcellus Shale estimated the impact of hydraulic fracturing well

development on the damage to each of five classes for roads maintained by the state, ranging from

Class A (Interstate Highways) to Class E (state-maintained roads that are not part of the national

highway system and were designed for less than 2,000 average daily traffic). These classes did not

include roads owned and maintained by boroughs and townships. Estimates of the cost (in 2012

dollars) of reconstructing one lane-mile ranged from $3.2 million for Class A to $2.3 million for Class

E. The estimates for the amount of useful road life that would be consumed by trucks associated

with hydraulic fracturing for each class, and an estimate of the damage cost per lane-mile for each

well, are shown here (Table 5).

Using the truck trip numbers from the New York EIS and assuming that each trip is 20 miles,

Abramzon estimated that, for all state roadway types, the consumptive road damage would be

$13,000 to $23,000 per well for all state roadway types. Light truck trips, empty truck trips, and local

roadways not maintained by the state were all excluded in this analysis, and the authors used the

number of truck trips estimated in the New York EIS. In this risk assessment, we assume a higher

number of truck trips. Scaling the cost to Maryland’s estimates would change the estimate to

$20,930 to $37,030 per well (Abramzon et al., 2014).

Table 5. Estimated consumptive road use and costs per lane-mile driven by trucks used for construction and operation of shale gas wells in Pennsylvania. Source: Abramzon et al., 2014.

Road Class A B C D E Total

Low truck trip range (some water delivered by pipeline)

Consumptive roadway use per well

0.0001% 0.0001% 0.0015% 0.0036% 0.0077%

Damage Costs per lane mile for each well

$2 $3 $40 $92 $180 $315

High truck trip range (all water delivered by truck)

Consumptive roadway use per well

0.0001% 0.0002% 0.0027% 0.0066% 0.0142%

Damage Costs per lane mile for each well

$3 $5 $72 $168 $331 $580

Even though the lane-mile reconstruction cost for an interstate highway is higher than that for a

Class E road, the damage from the additional truck trips is so minor on a state-maintained interstate

8

compared to a Class E road that the cost per lane-mile damaged for each well is ten times higher for

the Class E road ($331) than the cost for the interstate ($3) (Abramzon et al., 2014).

Second, a study in Keller, Texas estimated roadway damage maintenance costs from transportation

of water for hydraulic fracturing. The estimate was in the form of a fee to offset expected damages

per lane-mile of roadway. Varying by inclusion of pipelines and roadway characteristics, the fee

ranged from $53 to almost $20,000 per lane-mile (Table 6). The roadways’ base and surface material

specifications had the greatest impact on this range of fees, as opposed to pipeline use assumptions.

The costs only represent the reconstruction of the driving surface, and do not include the damage to

drainage infrastructure or other residual components (Belcheff & Associates, 2010).

A study prepared for Rio Blanco County, Colorado estimated roadway costs per gas or oil well

lifetime, including damage to roads as well as future growth and needed improvement required to

maintain current levels of service. The cost per oil or gas well lifetime was determined to be $18,762

in 2007 dollars (Table 6) (RPI Consulting, 2008).

Depending on the type of work needed and the characteristics of the road, the cost of roadway

repair can vary widely. In New York, low-level maintenance can start from under $100,000 per lane-

mile, but higher-level maintenance can be nearly ten times that cost. Furthermore, “full-depth

reconstruction” can surpass those costs. Bridges are also susceptible to damage. Bridges impacted

by enough truck traffic may need to be completely replaced. In New York, 166 bridges with

conditions from Fair to Poor were evaluated by the Department of Transportation for replacement;

costs ranged from $100,000 to tens of millions, averaging $1.5 to $3.3 million (Table 6) (NYSDEC,

2011).

Table 6. Road and bridge cost summary by study.

State Source Cost

PA Abramzon et al. 2014 $13,000 to $23,000 per well for all state roadway types ($2012)

TX Belcheff and Associates 2010 $53 to $19,977 fee per lane-mile of road

CO RPI Consulting 2008 $18,762 per gas or oil well lifetime ($2007)

NY NYSDEC 2011 $70,000 to $790,000 repair cost per lane-mile of road

NY NYSDEC 2011 $1.5 to $3.3 million average per bridge replacement

A Texas Transportation Institute study examined remaining roadway life following hydraulic

fracturing activity. Findings suggested that a new rural road would have lost nearly 40% of its design

9

life following the first year of development from one hundred horizontal gas wells. If the wells are

refracked every five years, the rural road’s pavement would fail in less than ten years (Quiroga et al.,

2012).

A Pennsylvania State Department of Transportation spokesman for their District 3 Office, Rick

Mason, said they observed “widespread, all-at-once wear and tear” on roads from natural gas

extraction activity. Managing the road impacts required more paperwork, field work, and cost than

anticipated; “we’re spending tens of thousands of dollars just on signs,” he said (Wilber, 2010).

The estimates discussed above considered damage from trucks that were not over-posted-weight.

The Pennsylvania Department of Transportation requires an Excess Maintenance Agreement from

haulers who may damage roads by using them for a significant number of over-posted-weight-

vehicles (30 or more loads or more per day and/or 600 or more loads per year). The hauler must

post a performance bond or irrevocable letter of credit in an amount based on the type of roadway;

for example, $6,000 per linear mile for unpaved roadways and $12,500 per linear mile for paved

roadways (Pennsylvania Department of Transportation DOT, 2011; 1 Pa. Code § 189).

Finally, community members’ vehicles can be damaged by driving on roads in disrepair. For

example, deep ruts along paved roads can mean that pavement between ruts extends high enough

to scrape the bottom of vehicles. Potholes and other cracked pavement can damage cars’

suspensions and wheels. The longer damaged roads persist, the more vehicle damage occurs.

Proposed mechanisms to help address roadway infrastructure damage from UGWD in Maryland are

discussed in the Proposed Best Management Practices section.

Traffic

UGWD will mean markedly increased traffic in communities near well pads. Increased gas

development traffic leads to congestion, a higher likelihood of vehicle collisions, and would impact

the character of rural communities.

Traffic congestion and community character

Increased traffic exacts a social cost and has been identified as a major community concern in areas

with natural gas development. Of 16 stakeholders from government, academia, industry,

environmental groups, and community organizations interviewed by the Pacific Institute, six

identified truck traffic on local roads as a concern (Cooley & Donnely, 2012). A study for New York

State called trucking “extensive” and named it “one of the largest” impacts to community character

10

(NTCC, 2011). Various citizen websites promote awareness of trucking issues associated with UGWD

based on negative experiences in their towns.

The impact of trucks on traffic flow will depend upon a number of characteristics including trucks’

routes, roadways’ functional classes, timing, and community population. Especially near well pad

access roads, traffic volumes could be substantial. Traffic could be heaviest during peak hours of the

day, some well development steps are much more truck-intensive than others, and multiple wells

could be completed in sequence. Increased employment in the area from well development will also

increase vehicle traffic. Larger roads designed to be more heavily traveled will be less impacted by

traffic, as with consumptive use damage. Conversely, smaller, more local roads are more susceptible

to both traffic congestion and damage (NYSDEC, 2011). Finally, road slopes in western Maryland

may impede traffic due to slow-climbing trucks.

On June 14, 2014, several members of Maryland’s Marcellus Shale Safe Drilling Initiative Advisory

Commission and the Risk Assessment team visited West Virginia UGWD drilling towns. Along US-50

to West Union, WV, the participants conducted an informal count and classification of vehicles

traveling east between 10:20 and 10:25 a.m. Approximately 13% of vehicles were UGWD-related

trucks hauling fluid, proppant, and other materials and equipment (11 UGWD trucks and 71-76

other vehicles). Though this survey cannot be considered representative, it gives some sense of

traffic increase on a major highway. In rural communities we observed in and near West Union,

most of the vehicles on some roads were UGWD trucks. Driving toward areas with active well pads,

the MD group was stopped by flaggers for up to 20 minutes so that trucks could move on the

narrow public road. The flaggers were employees of the UGWD companies who carried stop signs

and walkie-talkies to coordinate two-way traffic on one-lane public roads. Trucks were seemingly

constant throughout the day, and their traffic seemed to dominate movement in the communities.

In addition to the associated increase in costs, inconveniences, and concerns for safety, local vehicle

response and public safety services may need to increase their capacities to respond. This includes

ambulances, fire trucks, and police cars. Finally, greater need for traffic control may lead to required

installation of additional traffic signals, signage, and turn lanes (NYSDEC, 2011).

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Figure 1. Trucks associated with oil and gas extraction operations in Texas (TX DOT 2014).

Traffic accidents

An increase in traffic comes with a higher likelihood of accidents. A preliminary analysis indicates

that during Pennsylvania’s gas development boom in 2009-2010, counties with more than 20 shale

gas wells experienced a marked increase in total accidents and accidents involving heavy trucks. The

increase did not occur in counties with fewer than 20 or no gas wells. Prior to the gas development

surge in 2009-2010, the counties’ accident rates moved together; only after gas well development

did the accident rate in counties with well development diverge (Figure 2; Muehlenbachs &

Krupnick, 2014).

In counties that had, at the end of 2012, at least 20 gas wells, one additional well drilled in a county

per month was associated with an average 2% increase in accidents per month involving a heavy

truck, and a 0.6% increase in fatal accidents. Vehicle crash data were taken from Pennsylvania DOT’s

Crash Reporting System, and well data were obtained from the Pennsylvania Department of

Environmental Protection and the Department of Conservation and Natural Resources

(Muehlenbachs & Krupnick, 2014).

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Figure 2. Number of truck-related accidents in Pennsylvania counties with and without 20 or wore shale gas wells, per year (Muehlenbachs & Krupnick 2014).

Under the more intense drilling scenario (450 wells) evaluated for this risk assessment, Allegany

County would have one additional well drilled per month in year 2, and less than one per month in

all other years. Garrett County, on average, would have between 1 and 5 wells drilled per month

over the 10-year period.

An Associated Press article based on U.S. Census data has also found higher accident rates in

counties with oil and natural gas drilling. Per mile driven, drivers in North Dakota faced nearly twice

the likelihood of dying in a traffic accident in drilling counties compared to the rest of North Dakota

counties. The likelihood is 2.5 times greater in one drilling district in Texas as compared to the

statewide average. The authors noted that “Not all of the crashes involved trucks from drilling

projects, and the accidents have been blamed on both heavy equipment drivers and ordinary

motorists.” Table 7 summarizes other findings (Begos & Fahey, 2014):

Table 7. Summary of findings from Begos and Fahey 2014.

State Drilling counties Non-drilling counties

North Dakota Average death rate per 100,000 people up Average death rate per 100,000 people down

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148% from 2009-2013, compared with the previous five years

1% from 2009-2013 in the rest of the state

Texas Average death rate per 100,000 people up 18%

Average death rate per 100,000 people down 20% in the rest of the state

Pennsylvania Traffic fatalities up 4% from 2009-2013 Traffic fatalities down 19% from 2009-2013

New Mexico Traffic fatalities down 5% from 2009-2013 Traffic fatalities down 29% from 2009-2013

Begos and Fahey (2014) did not identify the criteria used to distinguish drilling counties from others.

The authors note that vehicle crashes often rise when the volume of traffic increases, but speculate

that the large number of heavy trucks needed for hydraulic fracturing, and the rapid pace of

development, have caused the rate of accidents to rise faster than the population or vehicle miles

traveled.

In Texas’ Permian Basin energy sector, the count of fatal crashes in 2012 increased by 27% from

2011, and 7% of reported 2012 crashes involving death or injury were with commercial trucks (TX

DOT, 2013). Following their observed increase in traffic and crashes from oil and gas production, the

Texas Department of Transportation and Department of Public Safety launched a public outreach

campaign to promote roadway safety in oil and gas work zones:

Historically, west Texas has not been an area where traffic was a concern, but now with a re-energized oil and gas industry, driving conditions have changed. ... Passenger vehicles are now sharing rural roads with more and more heavy trucks, and that’s a recipe for trouble when drivers don’t obey traffic laws, slow down or pay attention.

–John Barton, TX DOT deputy executive director (TX DOT, 2013)

Proposed mechanisms to help address traffic concerns are discussed in the Proposed Best

Management Practices section.

Ecological impacts

Creation and maintenance of roads sufficient to accommodate truck traffic can generate sediment

pollution and increase forest loss. The potential changes to water quality from construction

activities could impact aquatic species via sediment impacts to streams from road construction.

Sedimentation will have a negative effect on rare fish and sensitive mussels. Dirt/dust from truck

traffic can pollute streams. There is also potential for sediment impacts to streams from stormwater

flows during and after road construction.

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Clearing for access roads and pipelines can result in the loss of forest and can cause the creation of

additional forest edge. Forest roads have been shown to reduce terrestrial salamander movement

by 51% and with multiple roads dispersal could be reduced by up to 97% (Marsh et al., 2004).

Habitat loss/fragmentation and adverse impacts to wildlife corridors could also occur. Forest interior

dwelling species depend on large intact forested tracts. Forest clearing and additional creation of

edge will affect native plant communities because of canopy loss and introduction of invasive

species. Brush clearing could involve the removal of the riparian vegetation that is necessary to keep

aquatic temperatures low.

Depending upon location of construction activities, there could be downstream impacts to state

parks and water-based recreational activities. Increased heavy truck traffic will degrade the outdoor

recreational experience not only near the site, but the outlying travel areas. Potential adverse

impacts to water quality may affect streams and rivers (including wild and scenic rivers) used for

recreation.

Steps

The magnitude of truck traffic varies considerably by step in the well development process, as

broken down below. Where truck trip numbers are available, cumulative estimates are calculated

based on the two scenarios: 150 wells on 25 well pads, and 450 wells on 75 well pads. Summing

across steps, it is clear that hydraulic fracturing and well completion comprise by far the largest

proportion of truck trips throughout the process (Figure 3).

Figure 3. Percent of one-way, loaded truck trips attributable to each step in the UGWD process.

Site preparation

1%

Drilling 15%

Hydraulic fracturing &

well completion

80%

Site reclamation &

well abandonment

4%

Truck trips by step (one-way, loaded)

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Site identification

The purpose of site identification is to locate natural gas deposits and determine the most

appropriate well location. Developers conduct geologic exploration in areas identified as most likely

to meet necessary site characteristics. Sound waves directed downward can help characterize

geological layers and seismic conditions, shallow wells may be drilled, and brush may be cleared to

allow for equipment setup. A permit application submitted to MDE (Pennsylvania General Energy

Company) was reviewed here to give perspective on activities involved in seismic assessment

surveys. A 3.9-mile transect was delineated on foot. At intervals along this line, a drill buggy drilled

10- to 20-foot-deep “shotpoint” holes, which were filled with bentonite pellets. Finally, the crew laid

receivers and geophones along the transect, detonated them individually, and took recordings.

Equipment was then removed.

Trucking required during site identification is expected to be minimal and markedly less during site

identification than in other steps (Sammons/Dutton LLC and Blackenship Consulting LLC 2010). The

methods, time period, and type and amount of equipment and materials used vary. The duration of

site identification may be up to 120 days, based on the maximum time indicated on a permit

application to MDE.

Site preparation

Preparing a chosen site includes clearing land for the well pad, building the access road(s), possibly

improving existing roads, possible excavation for a freshwater pond, and transport of equipment

and materials. Site preparation is essentially a construction effort; trucks will be hauling

construction equipment, gravel, pipe, erosion and sediment control material, and other supplies, as

well as transporting construction crew and trailers. Approximate construction period estimates

include three weeks, three months (Chief Oil & Gas LLC 2010 , 2011), and up to four weeks per well

pad (NYSDEC, 2011).

The industry-estimated number of loaded, one-way truck trips required during site construction is

135 per well pad. For a well pad with six wells, assuming two drill rigs per well pad, this step

represents 1% of the estimated total 12,974 truck trips (Figure 3, Table 2). This proportion is

relatively small as compared to the rest of the process, but would be a noticeable increase in a rural

setting. Structural reinforcement, widening, and other upgrading of existing roadway infrastructure

as needed for the remainder of the UGWD operation would also be taking place where necessary

during this period.

The following numbers of truck trips are estimated to occur during site preparation:

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Scenario 1: 150 wells on 25 well pads in Maryland

25 well pads * 135 trucks per 6-well pad = 3,375 loaded, one-way truck trips

Doubled to include empty trips: 6,750 loaded and empty one-way truck trips




Drilling

During this step, natural gas rig(s) drill vertically from the prepared well pad, then the drill is turned

to drill horizontally. The well is cased and cemented and prepared for fracturing. Overweight and/or

oversized trucks hauling heavy equipment (e.g., drill rigs) will be traveling on the roads during this

step. Among materials trucked in will be drilling fluids, acid, and cement. After these initial

deliveries, fuel, maintenance supplies, and casing sections will be intermittently delivered (Chief Oil

& Gas LLC 2010, 2011). The waste cuttings and liquids drilled out from the well will be trucked out to

disposal facilities. Vertical and horizontal drilling could last between one and two months per well

(NYSDEC, 2011).

The four activities relevant to drilling in Table 1 total 1,970 one-way, loaded truck trips per six-well

pad. Rig mobilization and non-rig drilling equipment trips account for 28% of drilling trips and are

scaled based on the assumption of two drill rigs per well pad. Drilling fluids and drilling (rig crew,

etc.) account for 72% of the drilling trips and are proportional to the number of wells (six) on the

pad. Combining all truck trips estimated by the industry for UGWD, 15% is attributed to drilling

activities, making it the second-most-intensive step in trucking operations (Figure 3). The increase in

truck traffic from site preparation will be clear to nearby communities.

The following numbers of truck trips are estimated to occur during drilling:


25 well pads * 1,970 trucks per 6-well pad = 49,250 loaded, one-way truck trips


17




Hydraulic fracturing and well completion

The main step in the UGWD process is hydraulic fracturing. During this step, the horizontal length of

the well is perforated with small explosives in stages to make pathways for fractures to form.

Fracturing fluid comprised of water, chemicals, and solid proppants is then pumped into the well

and pressurized, forcing fluid and proppants into the shale formation through fractures. Once the

fractures are formed, a portion of the fluid returns to the surface, followed by natural gas.

Trucks haul millions of gallons of freshwater from freshwater source(s) to impoundments or other

water storage facilities located at the drill site. Though the actual hydraulic fracturing may take up to

5 days per individual well (NTCC, 2011), the delivery of the large volume of freshwater requires

approximately two to three weeks prior, and comprises the largest category of truck trips (46%).

Sand and chemical additive are subsequently delivered (Chief Oil & Gas LLC 2010, 2011). Equipment

is also trucked to the site throughout the process. This preparation period of hauling takes

approximately one to two months per well (NYSDEC, 2011).

After fracturing and well completion, hauls from the site will mainly transport produced water to the

disposal or treatment location. Since some of the fluid and proppants remain in the well after

hydraulic fracturing, the volume of produced water is less than the volume originally pumped into

the well. Hauling the produce water generally takes 2-8 weeks per well (NYSDEC, 2011). The

duration of hauling materials in, hydraulic fracturing, and hauling produce water out combines to

approximately 3 to 5.3 months per well for this step.

Once equipment has been used, it will be dismantled and trucked off the site, most likely to another

gas well. Dismantling is over a “more staggered” time period than assembly (Chief Oil & Gas LLC

2010, 2011).

All together, truck trips during hydraulic fracturing and well completion make up 80% of truck trips

required for UGWD, mainly due to the large volumes of water required (Figure 3Figure 3). These

large water volumes are unique to high volume hydraulic fracturing as compared to other

hydrocarbon extraction operations. For a well pad with six wells, this means more than 10,000 truck

18

trips (Table 2) over the time period that all these wells would be developed. Therefore, the most

roadway infrastructure damage and traffic risks exist during these steps.

The following numbers of truck trips are estimated to occur during hydraulic fracturing and well

completion:





75 well pads * 10,374trucks per 6-well pad = 778,050 loaded, one-way truck trips

Doubled to include empty trips: 1,556,100 loaded and empty one-way truck trips

Production/Processing, site reclamation, and well abandonment

Natural gas that emerges from a hydraulically fractured well must be processed and transported by

pipelines, either to a central processing plant offsite or to other transmission lines. The sections of

pipe are transported by truck and installed underground to connect the well to the gas distribution

network. Onsite, the gas may need to be processed by heaters, oil/water/gas separators, and

dehydrators to prevent condensation or crystallization of liquids in the gas. Onsite and offsite

compressors are used to maintain pressurization required to transport the gas the distance needed

through the pipelines.

Once the natural gas flow from the well has reduced significantly, liquid may periodically accumulate

within the well and hinder the flow of gas. Purging this liquid is called well unloading, and trucks are

needed to periodically transport this liquid offsite (Allen, 2013; U.S.EPA, 2006). Well unloading

events may occur 6 to 33 times per year (Allen, 2013). Additionally, some wells output condensate.

Collected condensate liquid is periodically trucked to refineries, approximately weekly (NYSDEC,

2011).

It is not clear whether truck trips in this step are included in Table 1 or Table 2 since “Final pad prep”

and “Miscellaneous” activity categories are not further explained in the primary source (ALL

19

Consulting, 2010). Here, these values are being used as estimates for this step, comprising 4% of

truck trips required to develop a 6-well pad (Figure 3).

Wells typically produce natural gas for many years and can continue for decades, especially if the

natural gas fields are “amenable to enhanced recovery techniques” (Sammons/Dutton LLC &

Blackenship Consulting LLC, 2010). The gas production rate will decrease over time. During

production, the operation will be dramatically less industrial, greatly reducing its impact on a

community’s character (Sammons/Dutton LLC & Blackenship Consulting LLC, 2010).

When a well is deemed no longer economically viable, a period which gradually overlaps with the

end of the production phase, it will be abandoned in accordance with regulations and the site will be

reclaimed. Trucking activity required for these activities is expected to be low. Following hydraulic

fracturing and completion, remaining truck activity at well sites will be “insignificant” over the long

term (NYSDEC, 2011), and will have “no appreciable impact on local traffic” (Chief Oil & Gas LLC

2010, 2011). Finally, general site maintenance such as lawn-mowing would occur approximately

twice a year (NYSDEC, 2011).

The following numbers of truck trips are estimated to occur during production/processing, site

reclamation, and well abandonment:







Proposed Best Management Practices

Many road damage and traffic risks can be mitigated through implementation of best management

practices (BMPs). In June 2013, the Maryland Department of Environment and Maryland

Department of Natural Resources proposed BMPs for natural gas production from Marcellus Shale

in Maryland. Thousands of public comments were received and the Interim Final Best Practices

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Report was released in July 2014. This risk assessment will assume that the best practices in the

Interim Final report are in place and followed if and when Marcellus Shale drilling begins in

Maryland. If appropriate, based on this risk assessment, the health report, or other information,

additional or strengthened best practices may be recommended in the Departments’ third report

under the Executive Order.

Fewer trips

Some practices in the UGWD process will inherently reduce the number of required truck trips. The

placement of multiple wells on a single well pad decreases the amount of truck traffic among wells,

various hauling sources, and destinations. Furthermore, horizontal wells allow for more shale access

than vertical-only wells allow, requiring distinctly fewer wells and well pads to extract an equivalent

amount of natural gas. Though the number of hauls required per horizontal well is greater than that

for vertical wells, truck traffic per area of land developed is cumulatively less with horizontal wells

(NYSDEC 2011). Also, a required BMP in Maryland will be the treatment and reuse of at least 90% of

flowback water on the well pad “unless the permittee can demonstrate that it is not practicable”

(MDE & MDNR, 2014). Because recycling reduces the demand for fresh water and reduces the

amount of wastewater to be disposed, it can substantially reduce the number of trucks hauling fresh

water to the pad and wastewater from the well pad (NYSDEC, 2011).

The transportation plan should consider moving heavy equipment by rail, if possible. Using pipelines

to transfer water to the site can also reduce truck trips. Pipelines could reduce truck traffic by 30% if

moving water between sites, but introduce right-of-way controversies, the risk of leaks (Cooley &

Donnely, 2012), and ecological impacts. Though using railways and pipelines would transfer some

risk to those pathways instead (NYSDEC, 2011), the reduction in road damage and traffic collisions

would make these safer alternatives for the nearby communities. Since each of these can only

substitute for some materials’ transport and a portion of overall truck routes, they cannot be

complete substitutes.

Transportation planning and road construction

Travel routes will be identified in the Comprehensive Gas Development Plan and incorporated into

individual permits as conditions. This planning can be used to establish truck routes that, to the

extent possible, avoid roads that are very close to homes, businesses, public buildings, and high use

recreational areas and direct traffic away from roads that cannot bear the traffic. Hours of road use

can also be specified to avoid peak hours and times when school buses are transporting students.

Once a transportation plan is approved and incorporated into the permit, it would become

enforceable (MDE & MDNR, 2014).

Transportation planning will occur during the CGDP process as well as the process for considering an

application for a drilling permit. The routes, hours, and times of travel should be restricted to avoid

or minimize conflicts with the public as well as sensitive wildlife migratory or mating seasons.

Participation by the public, state and county roads departments is encouraged. State public land

21

managers are also encouraged to participate so that consideration can be given to periods of heavy

public use such as hunting season or trout season, the impassability of roads during certain weather

conditions, and the increased risk of road damage during traditionally wet periods and the spring

frost breakup (MDE & MDNR, 2014).

Maryland’s BMPs specify that existing roads should be used wherever possible and that roads

constructed by private parties for access to gas exploration and production facilities should avoid

adverse environmental impacts and minimize those that cannot be avoided. The BMPs require that

the design, construction and maintenance of unpaved roads be at least as protective of the

environment as the guidelines adopted by the Pennsylvania Department of Conservation and

Natural Resources, Bureau of Forestry, for roads in leased State forest land (PA DCNR, 2013). This

includes modifying road elevation to restore drainage, sufficient compacting and top dressing,

geotextiles where required, dust control, and prompt stabilization of disturbed areas to prevent

erosion, among other specifications (PA DCNR, 2011). Additionally, forest fragmentation and

disturbance at stream crossings should be minimized. Existing Maryland sediment and erosion

control plans and stormwater management plans address this as well (MDE & MDNR, 2014).

Emergency response planning will include disclosure of the hazardous materials being transported

and advance consultation with emergency response personnel. This will reduce the risk to

emergency responders and the public in the event of a vehicle incident involving hazardous

chemicals (MDE & MDNR, 2014).

Road agreements

Applicants for gas well permits will be required to enter into agreements with the county and/or

municipality to restore the roads which it makes use of to the same or better condition the

roadways had prior to the commencement of the applicant’s operations, and to maintain the

roadways in a good state of repair during the applicant’s operations (MDE& MDNR, 2014). A

common form for such an agreement is a Road Use and Maintenance Agreement or RUMA.

The components of RUMAs vary, and the counties and/or municipalities will have to negotiate their

RUMAs with the drilling companies. It is common to require the company to post a bond to

reimburse the local jurisdiction in the event performance is not satisfactory. Additionally, RUMAs

can include requirements to improve and reinforce existing roads, bridges, clearance at

intersections, drainage facilities, and other relevant infrastructure along the truck route prior to the

start of natural gas development (NYSDEC, 2011).

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Existing tools

The costs for State road repair and maintenance for the increased traffic associated with UGWD may

be partially offset by the payment by trucks of fees and taxes, such as registration fees (apportioned

under the International Registration Plan) and motor fuel taxes (apportioned according to the

International Fuel Tax Agreement) (MDDOT, 2012). Where permits are obtained for overweight or

oversized vehicles, the State can require a contractual liability agreement to indemnify the State

Highway Administration of Maryland and the State of Maryland for all loss arising from damage to

the road beds and wearing surfaces of any highways and structures used by the permittee and all

sub-surface installations, and/or signs, signals, etc. (MDDOT, 2008). Counties also have programs

for overweight or oversized vehicles.

In Table 8, these tools are broken down by truck weight and type of road.

Table 8. Regulatory tools charging trucking operators for road damage.

Truck weight State roads County and municipal roads

Overweight and/or oversized

Overweight/oversize vehicle permit fee, plus payment for all damage caused1 State roadway taxes and fees (meant to provide for road upkeep)2

Overweight/oversize vehicle weight restrictions and/or charges: Garret County3, possibly others Expected RUMAs with operators to maintain roads and return to original conditions4

Not overweight or oversized

State roadway taxes and fees (meant to provide for road upkeep)2

Expected RUMAs with operators to maintain roads and return to original conditions4

1 (COMAR 11.04.01)

2 (MDE 2014)

3 (Garret County, MD Code of Ordinances 1971)

4 (MDE & MDNR, 2014), sample agreement: (Town of Windsor, 2010)

Flowback disposal onto roads not permitted

Finally, though Resources for the Future listed wastewater application to roads for deicing and dust

suppression as a risk (Krupnick et al., 2013), this practice will be not be allowed in Maryland. This

pathway is not explicitly addressed in the BMP document; however, the state will only allow

flowback disposal through authorized treatment and disposal facilities. Furthermore, the state

proposes that records be kept of flowback volumes at the well pad and the delivery facility to ensure

the arrival of all waters. These records will be made available for audits and/or inspections (MDE &

MDNR, 2014). Since flowback water will not be used for deicing and dust suppression in Maryland,

this risk is not applicable and was not examined in this document.

23

Risk Mitigation

Traffic and road damage issues have been documented in natural gas drilling areas even in the

presence of road agreements and safety requirements. Three main sources of these problems are:

1) issues with road use agreements, 2) safety compliance problems with trucks, and 3) the high rate

of highway accidents in the oil and gas industry.

Road use agreement issues

During the literature review for this risk assessment, some additional measures were specified that

could improve the structuring and enforcement of RUMAs. New York DEC recommended creating

video and photo road surveys to document prior road conditions (NYSDEC, 2011; Randall, 2010).

Other studies mentioned contracting with an engineering company to create plans or traffic impact

assessments prior to the start of trucking to help ensure cost accountability (Mitchell, 2010; Randall,

2010; Wilber, 2010). Enforcement of truck weight restrictions via periodic unannounced

enforcement sweeps, for example, is also recommended. RUMAs should be legally vetted to help

ensure their effectiveness (Mitchell, 2010; Randall, 2010). Collaboration among jurisdictions and

guidance from the state can prevent legal issues later on (Mitchell, 2010).

Passing a road preservation law is an alternative option. The legislature of Tompkins County, NY

adopted a County Road Preservation Law in 2011. Posting, permitting, and bonding requirements

are triggered when more than 1,000 truck trips are made by trucks weighing more than 30 tons

“News Details – Legislature Adopts Road Preservation Law”)

A road and bridge impact report prepared for Rio Blanco County, Colorado, recommended a road

impact fee schedule for residential, nonresidential, and gas or oil well development. The fee for gas

or oil well varied from $10,918 to $18,762 per well (2007 dollars) (RPI Consulting, 2008).

As part of Cornell University Law School’s Environmental Law Online Resource Center, a shale gas

drilling guide was prepared to advise local jurisdictions on road impact (Mitchell, 2010). As reported

in this document, the city of Fort Worth, Texas encountered issues with collecting bonds from the

UGWD companies and paying for road damage, despite a negotiated agreement in 2001. These

issues occurred despite that fact that the city hired engineers to photograph the roads both before

and after the drilling process had been completed. Small road repairs were paid by some drillers;

however, bonds had not yet been collected as of 2010 “because it has been too difficult to point the

finger at gas drillers for long-term road destruction.” Details of the agreement were not specified. A

subsequent effort to implement a permit fee instead was not adopted due to strong gas industry

opposition. Fort Worth attorney Sarah Fullenwider said that the city had not yet found a solution to

paying for road damage (Mitchell, 2010).

24

If counties, municipalities, and/or the state are left with infrastructure damage or reduced roadway

life unpaid for by the drillers, this will represent a negative externality. The cost, both monetary and

in terms of quality of life, will be borne by those jurisdictions and roadway users. As stated in the Rio

Blanco County, Colorado, road and bridge impact report:

If the County does not charge new development for its fair share of the costs, then existing taxpayers will bear the burden of building capacity related improvements. This results in a de-facto subsidy of new growth by the taxpayers at large. (RPI Consulting 2008)

Compliance

Noncompliance by trucks associated with natural gas development has been common in parts of

Pennsylvania. Pennsylvania State Police (PA Police) Commissioner Frank Pawlowski and

Pennsylvania DOT Secretary Allen Biehler reported that drilling has brought more truck traffic, traffic

violations, road damage, and crime. An enforcement effort in Susquehanna County, PA conducted

on February 9, 2010 found that 56% of 194 inspected trucks exceeded the weight limit. Of those

overweight trucks, 50% were also cited for safety violations. Also, road damage has not always been

repaired quickly, and has resulted in road closures due to safety concerns from “extensive damage.”

Additional state and local government resources were needed to address this increased need for

enforcement (PA DOT, 2010b).

In response to the observed increase in traffic and noncompliance of state laws, the PA Police

partnered with the Pennsylvania Department of Environmental Protection (PA DEP) in September

2010 to fund FracNet, an enforcement effort of unannounced roadside inspections for trucks

supporting natural gas extraction. In 2009, PA Police and the PA DEP inspected more than 4,300

trucks associated with drilling in the Marcellus shale as well as trash trucks. Of the 4,300, 62% were

issued citations and 18% were taken out of service. In June 2010, a joint effort to inspect trucks

hauling fracturing waste water carried out by PA Police, PA DEP, the Pennsylvania Public Utility

Commission (PA PUC), and the federal Motor Carrier Safety Administration resulted in 250 trucks

being placed out of service for safety deficiencies (PA DEP 2010b). Local newspapers have also

reported on inspected trucks exceeding weight limits, sometimes by many tons, and operating with

other safety violations (Wilber 2010; Whong 2010a, 2010b, 2010c).

In a letter to the PA PUC, PA Police Lieutenant Raymond J. Cook described safety issues “caused by

the recent influx of heavy trucks in the Marcellus Shale region.” From the significantly higher truck

traffic, he said the road infrastructure has crumbled to the point of posing “an immediate safety

concern.” Not only does this considerably hinder emergency service vehicles, but heavy trucks,

25

especially those with unsecured loads, “are more prone to rollover and crash when driven on an

unstable road surface.” From April 1 to June 7, 2010, more than 400 trucks supporting drilling

operations were inspected; either the driver or the vehicle was placed out of service in 56% of

inspections due to “serious safety violations.” In comparison, the expected federal rate is 24 to

30%. Also concerning was that 66% of trucks hauling hazardous materials were placed out of

service. Additionally, PA Police encountered the following issues (Cook, 2010):

Single-trip Special Hauling Permits were being used multiple times;

Weights exceeded permitted limits;

Trucks operated after sunset;

Trucks were found off their permitted travel routes;

Defective brakes were “common” safety violations;

Log records of duty status were at issue;

Loads were improperly secured.

To increase enforcement efforts and reduce violations, cost has increased. Resources have been

used to train more than 100 personnel, purchase additional weight scales, and educate stakeholders

including members of the industry, local district judges, and local law enforcement (Cook, 2010).

Roadway Accidents

Transportation incidents are the most common fatal event in U.S. industries overall. In 2006, for

example, transportation incidents accounted for 42% of the workplace fatalities; of these, more

than half were on the highway. During the 2003 to 2009 Census of Fatal Occupational Injuries, 716

oil and gas extraction workers were killed on-the-job, resulting in an annual fatality rate of 27.5

deaths per 100,000 workers (compared to 3.9 for all U.S. workers). Of these 716 deaths, 29 percent

were highway motor vehicle crashes (CDC, 2012).

The CDC noted that there was a correlation between fatality rates and the number of active drilling

rigs. It speculated, “This could be a result of an increase in the proportion of inexperienced workers,

longer working hours (more overtime), and the utilization of all available rigs (older equipment with

fewer safeguards).” Fatigue is obviously an important risk factor in motor-vehicle crashes. Oil and

gas workers may be especially fatigued for a number of reasons. Many operations on the drill pad go

on 24 hours a day, 7 days a week. During drilling, workers often work 8 or 12 hour shifts and work

for up to 14 days in a row before taking a lengthy break. The Federal Motor Carrier Safety

Administration (FMCSA) sets hour of service rules for commercial motor vehicles (CMV) (49 CFR

395). Drivers in the oil and gas industry are exempt from some of the hours of service rules that

otherwise apply to CMV drivers. This is referred to as the “oilfield exception.”

Oil and gas industry drivers, like other CMV drivers, must have 10 consecutive hours off-duty before

starting a work day. That work day may not extend beyond 14 hours, 11 hours of which may be

driving time. Oil and gas industry drivers, like other CMV drivers, are limited to being on duty for no

more than 60 hours in any consecutive period of 7 days or 70 hours in any consecutive period of 8

days. Drivers of commercial motor vehicles used exclusively in the transportation of oilfield

equipment and servicing of field operations of the natural gas and oil industry, however, may

26

“reset” the work week with an off-duty period of 24 or more successive hours, compared to 34

consecutive hours for other CMV drivers. This “reset” rule applies to trucks carrying water and sand,

as well as other material used in the servicing of field operations (49 CFR 395.1(d)(1)). The work day

limits still apply.

Another part of the oilfield exception applies to a subset of CMV drivers in the oil and gas industry –

“specially trained drivers of commercial motor vehicles that are specially constructed to service”

natural gas or oil wells. This exemption addresses whether waiting time is on-duty time or off-duty

time (49 CFR 395.1(d)(2)). These drivers are allowed to accumulate the requisite 10 hours of off-duty

time before beginning a work day in shorter rest periods. These rest periods are not counted against

the next 14-hour workday, although the 11-hour driving time still applies. This exception does not

apply to drivers of CMV who are delivering supplies, including water and sand. It was apparent that

some drivers and states were misinterpreting the scope of the oilfield exemption. In guidance,

FMCSA clarified this exception:

The “waiting time” provision in Section 395.1(d)(2) is available only to operators of those commercial motor vehicles (CMVs) that are (1) specially constructed for use at oil and gas well sites, and (2) for which the operators require extensive training in the operation of the complex equipment, in addition to driving the vehicle. In many instances, the operators spend little time driving these CMVs because "leased drivers" from drive away services are brought into move the heavy equipment from one site to another. These operators typically may have long waiting periods at well sites, with few or no functions to perform until their services are needed at an unpredictable point in the drilling process. Because they are not free to leave the site and may be responsible for the equipment, they would normally be considered "on duty" under the definition of that term in § 395.2. Recognizing that these operators, their employers, and the well site managers do not have the ability to readily schedule or control these driver’s periods of inactivity, Section 395.1(d)(2) provides that the "waiting time" shall not be considered on-duty (i.e., it is off-duty time). During this "waiting time," the operators may not perform any work related activity. To do so would place them on duty. Examples of equipment that may qualify the operator/driver for the "waiting time exception" in Section 395.1(d)(2) are vehicles commonly known in oilfield operations as heavy-coil vehicles, missile trailers, nitrogen pumps, wire-line trucks, sand storage trailers, cement pumps, "frac" pumps, blenders, hydration pumps, and separators. This list should only be considered examples and not all-inclusive. Individual equipment must be evaluated against the criteria stated above: (1) Specially constructed for use at oil and gas well sites, and (2) for which the operators require extensive training in the operation of the complex equipment, in addition to driving the vehicle infrequently. Operators of CMVs that are used to transport supplies, equipment, and materials such as sand and water to and from the well sites do not qualify for the "waiting time exception" even if there have been some modifications to the vehicle to transport, load, or unload the materials, and the driver required some minimal additional training in the operation of the vehicle, such as running pumps or controlling the unloading and loading processes. It is recognized that these operators may encounter delays caused by logistical or operational situations, just as other motor carriers experience delays at shipping and receiving facilities. Other methods may be used to mitigate these types of delays, which are not the same types of waiting

27

periods experienced by the CMV operators who do qualify for the waiting time exception. (77 FR 33098)

The FMCSA confirmed this interpretation in 2013 (78 FR 48817).

In 2000, the FMCSA proposed to alter the oilfield exemption to become more consistent “with the

modern understanding of fatigue” and thereby reduce fatigue-induced crashes. These modifications

were intended to “allow those drivers to get the restorative sleep the research suggests they need

to ensure their own safety and that of others” (65 FR 85). The industry opposed these changes and

the oilfield exemption remains in place.

In 2010, FMCSA proposed changes to the hours of service rules (75 FR 249). In commenting on the

proposed regulations, the National Transportation Safety Board, the federal agency responsible for

investigating accidents, supported some of the changes, but repeated its strong opposition to

leaving in place special provisions that exempt some drivers from the hours of service requirements,

including the oilfield exception. It noted, “Such exemptions are likely to lead to increased risk for the

exempted population and the driving public” (Hersman, 2011). Kenny Jordan, executive director of

the Association of Energy Service Companies, stated that the problem comes not from the

exemption, but that “it is the enforcement of the existing rule that is the issue” (Jordan, 2010;

Urbina, 2012).

There is general agreement that driver fatigue issues exist and persist in the industry. The

combination of driver fatigue and documented low rates of compliance with truck safety rules in

some locations raises the risk of transportation incidents that can kill or injure not only the worker,

but also members of the public who use the same roads.

Conclusion

Overall, UGWD will bring a significant increase in truck traffic to nearby communities. This will lead

to roadway infrastructure damage as well as corresponding increases in traffic hindrances and

accidents. BMPs will help mitigate these risks, but they cannot be eliminated. Residents living along

a truck route near a well pad could expect to see many thousands of trucks going by their homes

over years of well development:

28





75 well pads * 9,358 trucks per 6-well pad =701,850 loaded, one-way truck trips

Doubled to include empty trips: 1,403,700 loaded and empty one-way truck trips

Prevention and repair of road damage on county and municipality roads will be dependent on

agreed-upon transportation plans and road use agreements. Legal vetting of the local RUMAs and

documentation of road conditions before, during, and after the activity will be critical to ensuring

drillers’ performance of their obligations, as will communication and transparency among parties.

Short term, there will likely be road damage prior to time of repair. That damage may not be

promptly repaired if disagreements among parties (UGWD operators and local jurisdictions) occur

concerning responsibility and extent of payment on a case-by-case basis. Larger state roads will

experience some level of reduced roadway life, but repair is financially supported by state taxes and

fees, not road use agreements. Whether the full cost of the reduced roadway life will be covered by

the state taxes and fees is unclear. The estimation of probability and consequence, and risk ranking

appears in Table 10. Cumulative risks across phases appear in Table 11.

The projected increase in trucking accidents could result in injuries or fatalities. This outcome is a

social cost of economic growth that occurs with other industries as well, but part is unique to UGWD

due to the large volume of water required and the fatigue that workers and drivers experience. As

stated in a study for New York state, “One of the largest and most obvious potential impacts on

community character is the issue of trucking” (NTCC, 2011). A summary of the sources of the risk,

the harm, and the BMPs appears in Table 8. The estimation of probability and consequence, and risk

ranking appears in Table 10. Cumulative risks across phases appear in Table 11.

Finally, the ecological impacts of road construction and traffic include habitat loss, fragmentation,

increased sedimentation, stormwater runoff, and recreation impacts. The estimation of probability

and consequence, and risk ranking appears in Table 10. Cumulative risks across phases appear in

Table 11.

29

Table 9. Summary of causes, effects, and BMPs.

Road damage Traffic impacts to community Ecological impacts

Sources of Risk Number of truck trips Truck weight, both in and out of compliance Potential issues with payment for road infrastructure repairs

Number of truck trips Safety violations like unsecured loads, defective brakes Worker and driver fatigue

Number of truck trips Road construction and modification

Results / Consequences of Risk

Road damage and associated repair costs of varying magnitudes, short-term and potentially long-term Higher risk of rollover of heavy/ unsecured trucks on damaged roads Hindrance to emergency services including ambulances, police, fire Congestion and detriment to travel for community residents Damage to residents’ vehicles driving on cracked and/or rutted roads

Injuries, fatalities from crashes Hindrance to emergency services including ambulances, police, fire Congestion and detriment to travel for community residents Change in character of rural communities Local cost to increase enforcement and traffic control infrastructure

Sedimentation, pollution of surface water Forest fragmentation and loss Corresponding detriments to fish and wildlife Outdoor recreational impacts

Proposed BMPs Fewer trucks via: multiple wells per wellpad (HVHF), use of horizontal wells, reuse of flowback water, and use of rail and pipelines Road agreements to reduce costs, prevent damage and/or reduce time that roads are in disrepair Transportation plans to define routes and timing

Fewer trucks via: multiple wells per wellpad (HVHF), use of horizontal wells, reuse of flowback water, and use of rail and pipelines Road agreements to help prevent damage and/or reduce time that roads are in disrepair Transportation plans to define routes and timing

Location of access roads considered in CGDP Road construction must minimize environmental impacts via construction standards for forest roads Transportation plans to define routes and timing Forest loss and stream crossing disturbance should be minimized

30

Table 10. Summary of probability, consequence and risk ranking for a single well pad.

Phase Occurrence Impact Probability Consequence Risk Ranking

Site identification Truck traffic Road Damage/ Accidents/ Ecological and Recreational

Low Low Low

Site preparation Truck traffic Road Damage/ Accidents/ Ecological and Recreational

Low Moderate Low

Drilling

Truck traffic Road Damage/ Accidents/ Ecological and Recreational

Moderate Moderate Moderate

Hydraulic Fracturing and Well Completion

Truck traffic Road Damage High Moderate High


Truck traffic Accidents High Serious High


Truck traffic Ecological and Recreational Moderate Moderate Moderate

Production/Processing, site reclamation, and well abandonment

Truck traffic Road Damage/ Accidents/ Ecological and Recreational

Low Low Low

31

Table 11. Summary of cumulative risk ranking.

Aspect Agent/ chemical Impact on Phase

Site identification/ preparation



Production Well abandonment/ reclamation

Traffic Cost of repair of road damage


Traffic Increased risk of roll-over, etc. from road damage


Traffic Damage to residents’ vehicles from road damage


Traffic Delays and inconvenience Community Low Low Moderate Low Low

Traffic Delay of emergency vehicles Community Low Moderate High Low Low

Traffic Loss of rural character Community Low Low Moderate Low Low

Traffic Increased cost of policing Community Low Low Moderate Low Low

Traffic Interference with outdoor recreation

Community Low Moderate Moderate Low Low

Accidents Injury and death Community Moderate High High Moderate Moderate

Traffic Damage to wildlife Ecological Low Low Low Low Low

Road construction

Forest fragmentation, sediment, harm to wildlife

Ecological Moderate Low Low Low Low

32

Suggestions for Additional Mitigation

It is clear that a major risk factor in HVHF is truck traffic, especially trucks carrying water to the

wellpad. The use of central water impoundments and pipelines to transfer the water to the wellpad

could reduce the amount of traffic, but large impoundments must still be filled with water, and

pipelines have ecological impacts. A better solution would be use of a different technology that

allows fracturing without the use of such large quantities of water. The Departments and the

Advisory Commission have learned that such technologies are being developed, although it is not

clear whether they are suitable for the Marcellus Shale in Maryland or what impacts they might

have. They include the use of liquid CO2 as the fracturing fluid or the use of solid rocket propellant

in place of the fluid. If such technologies are feasible, Maryland could require their use in place of

water-based fracturing fluid.

33

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i

Appendix D:

Drilling Fluid and Cuttings

Table of Contents

Introduction ............................................................................................................................................................ 1

Drilling Process Overview ....................................................................................................................................... 1

Activity, Risk Identification and Risk Assessment ................................................................................................... 5

Transport of Drilling Fluid Additives to the Well Pad ............................................................................................. 5

Drilling Fluid Preparation ........................................................................................................................................ 9

Drilling Operations ................................................................................................................................................ 13

Well blowout during drilling ................................................................................................................................. 16

Drilling Cuttings Separation, Storage and Transfer for Disposal .......................................................................... 20

Waste Drilling Fluids Storage ................................................................................................................................ 23

Transport of Used Drilling Fluids from the Well Pad ............................................................................................ 27


Sources for Figures ............................................................................................................................................... 32

References ............................................................................................................................................................ 32

Figure 1: Triple rotary rig ........................................................................................................................................ 2

Figure 2: Blowout prevention system..................................................................................................................... 3

Figure 3: Closed-loop drilling .................................................................................................................................. 4

Figure 4: Diagram of a closed-loop drilling fluid system ........................................................................................ 5

Figure 5: Risk flowchart for the transport of drilling fluid additives to the well pad ............................................. 9

Figure 6: Risk flow chart for drilling operations ................................................................................................... 13

Figure 7: Risk flow chart for drilling operations ................................................................................................... 16

Figure 8: Risk flow chart for well blowout ............................................................................................................ 19

Figure 9: Risk Flow chart for drilling cuttings separation, storage and transfer for disposal ............................... 22

Figure 10: Risk flow chart for waste drilling fluid storage .................................................................................... 26

Figure 11: Risk flow chart for transport off-site of waste drilling fluids and cuttings for disposal ....................... 30

Table 1: Risk Assessment table ............................................................................................................................. 31

1

Introduction

This section evaluates the environmental risks associated with drilling during unconventional gas

well development (UGWD). The drilling process requires the use of air or drilling fluids to cool and

lubricate the drill bit. These fluids also aid in the removal and transport of cuttings from the

borehole to the surface for containment. The cuttings are removed from the drilling fluids using

separation equipment (e.g., mud shakers). The drilling fluids are then re-circulated to the well for

reuse. The cuttings may contain naturally occurring radioactive materials (NORM) as well as heavy

metals and other chemical contaminants present within the rock formations that have been drilled.

Drilling fluids may also contain chemical additives as well as oil or polymer compounds depending

on the fluid type selected for the drilling process. In addition the fluids may contain the same

compounds found in the cuttings once they have come into contact (NYSDEC, 2011). Accidental

releases or spills of drilling fluids or cuttings could potentially contaminate soil, surface water and

ground water. These accidents may occur on the well pad or off-site during the transport of drilling

fluid chemical additives and waste materials. This chapter will provide an overview of the drilling

process, identify the risks associated with the various stages in the drilling process, present existing

regulations or proposed BMPs which may reduce or mitigate these risks, and provide an overall risk

assessment. Risks associated with ground water contamination due to methane migration from

within the well, methane releases to the air from drilling muds, and the disposal of waste drilling

fluids and cuttings will be addressed in another section.

Drilling Process Overview

Unconventional gas wells are generally drilled to a depth of 500 feet above the target shale

formation before directional drilling is initiated to drill the horizontal portion of the well (NYSDEC,

2011). Previous applications for gas well development in Maryland by Chief Oil and Gas LLC

indicated wells would be drilled to a total vertical and total measure depth of around 9,000 feet and

12,000 feet, respectively (Chief Oil & Gas LLC 2010, 2011). Directional drilling requires that a down-

hole motor be connected behind the drill bit at the end of the drill pipe (NYSDEC, 2011)

2

Multiple rotary rigs may be required to complete the drilling operation for a horizontal well. A

smaller rig would drill the vertical portion while a larger rig would drill the horizontal portion. Multi-

well sites may have two rigs on a well pad at one time. Rotary rigs are generally classified by height

where a single is 40-45 feet high, a double is 70 -80 feet high, and a triple is over 100 feet high.

Triple rotary rigs are commonly used for drilling wells for Marcellus Shale natural gas extraction (See

Figure 1). Auxiliary drilling equipment includes tanks for water and drilling fluids, generators,

compressors, solids control equipment, choke manifold, accumulator, pipe racks and office space. It

may take up to five weeks to complete the drilling operation including cementing and casing

(NYSDEC 2011). A horizontal well will include conductor, surface, intermediate, and production

casing. The surface casing extends below all freshwater aquifers and is cemented in place within the

borehole to ensure that fluids and gases within the well do not escape into the ground water.

Figure 1: Triple rotary rig

3

A blowout prevention (BOP) system is installed in all gas well operations to prevent a release of

drilling mud, formation fluids, or equipment in the event unexpected pressure is encountered in the

wellbore during drilling operations. (See Figure 2). A blow out may cause significant damage to the

equipment, injury or death to the workers, and environmental contamination.

The drilling process requires the use of drilling fluids to cool and lubricate the drill bit, provide

stability to the borehole, and prevent formation fluids from entering the wellbore. These fluids also

aid in the removal and transport of cuttings from the borehole to the surface for containment. The

vertical portion of the well passing through the freshwater aquifer zone can only be drilled using

compressed air or freshwater based drilling fluids. The horizontal portion of the well is generally

drilled using fluids that are water, polymer or oil based (NYSDEC, 2011). Various chemical additives

are also incorporated in order to improve the performance of the drilling fluid.

Drilling fluids are contained in a closed-loop system (See Figure 3). The drilling fluids are pumped

from storage tanks down the well through the drill string and out the drill bit. The fluids then return

to the surface containing the drill cuttings and flow to the separation equipment where the fluids

are separated from the cuttings and re-circulated back to the storage tanks for reuse. Separation

equipment is dependent on fluid type and may consist of shale shakers, de-sanders, and de-silters.

Additional equipment such as drying shakers, rotary cuttings dryers, squeeze presses or centrifuges

Figure 2: Blowout prevention system

4

may be required to further separate liquids from cuttings for reuse (NYSDEC, 2011). A diagram of

the closed-loop drilling fluid system depicting the steps in the recirculation and separation process is

displayed in Figure 4.

Following completion of the drilling process, including casing and cementing, the well will be

prepared for hydraulic fracturing. The drilling rig and auxiliary equipment will be removed from the

site and waste drilling fluids and cuttings will be transported and disposed of properly.

Figure 3: Closed-loop drilling

5

Figure 4: Diagram of a closed-loop drilling fluid system

Activity, Risk Identification and Risk Assessment : Transport of Drilling Fluid Additives to the Well Pad

Risk Identification

Drilling fluids used in UGWD may be aqueous (i.e., water-based) or non-aqueous (i.e. oil-based).

Chemical additives may also be required to improve the performance of these fluids. An aqueous

drilling fluid would generally be composed of the following chemicals by weight: brine/water (76%),

barite (14%), clay/polymer (6%) and other chemical additives (4%). A non-aqueous drilling fluid

would generally be composed of the following chemicals by weight: non-aqueous fluid (46%), barite

(33%), brine (18%), emulsifiers (2%), and gellants/other chemical additives (1%) (IPIECA 2009). The

transportation of chemical additives that are classified as hazardous materials is regulated by federal

law. Among the requirements are proper containers, shipping papers, marking, labeling, placarding,

emergency response information and an emergency response telephone number.

Vehicular accidents involving trucks transporting these chemical additives may result in the release

of vehicle fluids (fuel, antifreeze, etc.) or the cargo if the tank trucks or containers are compromised

or rupture. The released material could potentially contaminate soil, ground water or surface water

if clean up does not occur in a timely manner prior to infiltration or run off to surface water. In

recent years, large trucks have accounted for approximately 6 percent of all highway crashes,

accidents and incidents. (US DOT, 2013). Of the 15,433 hazardous materials transportation

6

incidents in 2012, 13, 241 were on the highway or in truck terminals, of which 362 (2.3 percent)

were accident-related. Most of the other incidents involved human error or package failure, and

were likely to occur during loading or unloading. (US DOT, 2013). There are more than 800,000

shipments of hazardous materials per day in the United States (Craft, 2004). The most recent

tabulation of incidents (2004-2013) by the Pipeline and Hazardous Materials Safety Administration

reported that the annual average number of incidents involving hazardous materials and highway

transportation was 14,074. (PHMSA 10 year Incident Summary Report). Based on 800,000 shipments

per day over a year and 14,074 incidents per year, not all of which resulted in a release of hazardous

materials to the environment, the probability that a shipment of hazardous materials would result in

a release would be less than 0.005% [14,074 incidents per year / (800,000 shipments per day x 365

days per year)]. No information on incidents related specifically to drilling fluid additive spills was

found following an extensive literature search.

A single unconventional gas well requires 45 heavy truck trips for delivery of chemical additives.

Another 140 light truck trips are also required for rig mobilization, drilling fluids, and non rig drilling

equipment (NYSDEC, 2011). The liquid chemical additives for drilling fluids are typically transported

in bulk totes referred to as intermediate bulk containers (IBCs). The dry chemical additives are

transported on flat-beds in bags set on pallets or in plastic buckets (NYSDEC, 2011). Under risk

assessment scenarios 1 (150 total wells) and 2 (450 total wells), a total of 6,750 (45 truck trips x 150

wells) and 20,250 (45 truck trips x 450 wells) one-way heavy truck trips, respectively, would be

required for transport of chemical additives. Assuming an incident probability of 0.005% under risk

assessment scenarios 1 and 2, 0.3 and 1 incidents involving the release of drilling fluid additives

during transport would occur, respectively, during the delivery of chemical additives to all the well

pads.

Risk Mitigation: Current Regulations and Proposed BMPs

Current Federal regulations and best management practices (BMPs) proposed by Maryland will

reduce the risk of soil, surface water or ground water contamination from accidental releases or

spills of drilling fluid additives that are hazardous materials during transport. Federal regulations (49

CFR Part 178) set minimum standards and integrity testing requirements for IBCs to ensure that they

can withstand normal conditions of transportation. Each IBC must be manufactured and assembled

so as to be capable of successfully passing the prescribed tests. This testing includes qualifying in

the performance of drop, leak-proofness, hydrostatic pressure, stacking, bottom-lift or top-lift, tear,

topple, righting and vibration tests. The specific conditions of the tests (e.g. drop height) are

determined by the physical characteristics of the substance intended to be transported.

Maryland proposes the following BMPs that are relevant to protection of the soil, surface water and

ground water from releases of drilling additives during transportation or off-loading:

7

Identification of travel routes in the Comprehensive Gas Development Plan

Avoidance of siting well pads on land with greater than 15 percent slope

No well pads within the watersheds of public drinking water reservoirs

All surface disturbance for pads, roads, pipelines, ponds and other ancillary infrastructure will be prohibited on State owned land, unless DNR grants permission

The term “well pad” is defined to include the areas where drill rigs, pumps, engines, generators, mixers and similar equipment, fuel, pipes and chemicals are located. No discharge of potentially contaminated stormwater or pollutants from the pad shall be allowed. Drill pads must be underlain with a synthetic liner with a maximum hydraulic conductivity of 10-7 centimeters per second and the liner must be protected by decking material. Spills on the pad must be cleaned up as soon as practicable and the waste material properly disposed of in accordance with law. The well pad must be surrounded by an impermeable berm such that the pad can contain at least the volume of 4.0 inches of rainfall within a 24 hour period. The design must allow for the transfer of stormwater and other liquids that collect on the pad to storage tanks on the pad or to trucks that can safely transport the liquid for proper disposal.

Each permittee must prepare a site-specific emergency response plan and the permittee must provide a list of chemicals and corresponding Safety Data Sheets to first responders before beginning operations. Facilities must develop plans for preventing the spills of oil and hazardous substances, using drip pans and secondary containment structures to contain spills, conducting periodic inspections, using signs and labels, having appropriate personal protective equipment and appropriate spill response equipment at the facility, training employees and contractors, and establishing a communications plan. In addition, the operator shall identify specially trained and equipped personnel who could respond to a well blowout, fire, or other incident that personnel at the site cannot manage. These specially trained and equipped personnel must be capable of arriving at the site within 24 hours of the incident.

Setbacks from the edge of drill pad disturbance o 450 feet from aquatic habitat o 600 feet from special conservation areas o 750 ft setback from downdip side of limestone outcrops to borehole o 2,000 foot setback from a private drinking water well o 1,000 foot setback from the perimeter of a wellhead protection area or source water

assessment area for a public water system for which a Source Water protection Area has been delineated

o No well pads on land at an elevation equal to or greater than the discharge elevation of a spring that is used as the source of domestic drinking water by the residents of the property on which the spring is located, but not to exceed 2,500 feet unless a delineation of the recharge area prepared by a registered geologist, and approved by the Department

State agencies will develop standard protocols for baseline and environmental assessment monitoring, recordkeeping and reporting. In addition, the State agencies will develop standards for monitoring during operations at the site, including drilling, hydraulic fracturing, and production

The monitoring, recordkeeping and reporting requirements will assist with identification of impacts from hazardous material releases so that remediation can be appropriate.

Risk Assessment

The probability of a hazardous material cargo release for a single shipment has been estimated

above as 0.005%. This would indicate 0.3 incidents (0.005% probability x 6,750 truck trips) and 1

incident (0.005% probability x 20,250 truck trips) incidents for all truck trips under risk assessment

scenarios 1 and 2, respectively. If a release or spill did occur during a vehicular accident, the

probability of soil, surface water or ground water contamination by hazardous materials would be

reduced if the spill were properly identified, contained and cleaned up. These steps are considered

8

likely to occur because of the federal requirements for marking, labeling, placarding, emergency

response information and an emergency response telephone number. There is the potential that

chemicals could infiltrate the ground prior to emergency response team arrival on site or be

conveyed by surface runoff if the accident occurs during a rain event. Spills associated with dry

chemical additives are less likely to contaminate surface or ground water since infiltration or

transport within surface runoff will only occur due to dissolution during a rain event. The probability

that hazardous materials would be released during transport is considered low, and the existence of

emergency response plans further lowers the risk that the released material would contaminate soil,

surface water or ground water. If the release were to occur during off-loading the requirements for

clean up of spills on the pad and secondary containment would reduce the likelihood that the

material would reach soil, surface water or ground water. The frequency of surface water or ground

water contamination from accidental releases or spills of drilling fluid additives during transport is

also considered low on a cumulative basis.

Soil contamination is likely to be localized and contaminated soil could be removed. This

consequence will be classified as moderate because it could have an adverse impact in the

immediate vicinity, causing localized or temporary environmental damage. Contaminated ground

water could impair water quality in public and private wells at levels that adversely affect human

health through water consumption. If an incident resulted in the release or spill of drilling fluid

additives transporting directly into a stream the contaminated surface water could significantly

impair water quality and adversely affect the health of aquatic life. The consequences associated

with surface water or ground water contamination from accidental releases or spills of drilling fluid

additives during transport will be classified as moderate because these could have a considerable

adverse impact on people and the environment causing localized damage. For both risk assessment

scenarios 1 (150 wells) and 2 (450 wells) the consequences will be classified as moderate for soil

contamination and moderate for ground water and surface water contamination. Figure 5 presents

a flow diagram of the risk pathway for soil, surface water and ground water contamination

associated with the transport of drilling fluid additives to the well pad.

Impact Assessment: Release during transport of drilling fluids and additives to well pad

Impact Probability Consequence Risk Ranking

Human Low Moderate Low

Ecological Low Moderate Low

9

Figure 5: Risk flowchart for the transport of drilling fluid additives to the well pad

No

contamination of

soil, surface or

ground water

No

Yes

No

Surface or ground

water contamination

No

Yes

Yes

Are drilling fluid

additives released during

transport or off-loading?

Was spill cleaned

up from soil and

before it could

reach ground water

or surface water?

No

contamination of

soil, surface or

ground water

Were drilling

additives contained?

Soil contamination

No

contamination of

surface or

ground water

10

Drilling Fluid Preparation

Risk Identification

Before a drilling operation can proceed, the drilling fluids are prepared in storage tanks within a

closed loop system. Chemical additives used in the preparation of drilling fluids may either be liquid

or dry. Liquid additives will be contained in storage tanks while dry additives will most likely be

contained in bags on palettes or in plastic containers. In a closed loop system the liquid chemical

additives will be transferred to the drilling fluid storage tanks for mixing through hoses while dry

additives would be poured directly into the tanks which are open at the top. The potential exists for

liquid chemical additives to be released accidentally due to line ruptures, leaks, or operational error.

Dry chemical additives could also be accidentally spilled on the ground from operational error.

These release or spills have the potential to contaminate soil, surface water and ground water if

they are not properly contained. A study conducted by the New York State Water Resources

Institute (NYSWRI) identified that 8% of wells drilled in Bradford County, PA in 2010 had violations

handed out to gas well operators for spills/leaks on the well pad (NYSWRI, 2012). This study did not

distinguish in which stage of UGWD these spills or leaks occurred or whether it resulted in the

transport of contaminants off the well pad. This statistic only applies to spills or leaks for which the

State of Pennsylvania issued a citation and therefore the incidence rate would likely be greater. On

the other hand, because the spills or leaks could have occurred at any stage of UGWD, it is likely that

fewer spills or leaks occurred during any individual stage. For the purposes of this risk assessment, it

will be assumed that there is an 8% likelihood of a spill or leak at every stage of UGWD. Assuming

an 8% probability of a spill or release occurring on-site, under risk assessment scenarios 1 (150

wells) and 2 (450 wells), 12 (8% probability x 150 wells) and 36 (8% probability x 450 wells) incidents

would occur, respectively for all UGWD in Maryland. No additional information on incidents related

specifically to releases or spills of drilling fluid additives was found following an extensive literature

search. Drilling fluid preparation is a short-term process (on the order of a few days) therefore any

spills or releases that occur would most likely only account for a small percentage of the total spills

or leaks that occur on the well pad during the entire gas well development process.


Maryland proposes the following BMPs that are relevant to protection of the soil, surface water and ground water from releases during mixing of the drilling additives:

Storage of chemicals in tanks or containers on the well pad with secondary containment




The term “well pad” is defined to include the areas where drill rigs, pumps, engines, generators, mixers and similar equipment, fuel, pipes and chemicals are located. No discharge of potentially contaminated stormwater or pollutants from the pad shall be allowed. Drill pads must be underlain with a synthetic liner with a maximum hydraulic conductivity of 10-7 centimeters per second and the liner must be protected by decking material. Spills on the pad must be cleaned up as soon as practicable and the waste material properly disposed of in accordance with law. The well pad must be surrounded by an impermeable berm such that the pad can contain at least the volume of 4.0 inches of rainfall within a 24 hour period. The

11

design must allow for the transfer of stormwater and other liquids that collect on the pad to storage tanks on the pad or to trucks that can safely transport the liquid for proper disposal.

Tanks shall be above ground, constructed of metal or other material compatible with the contents, and lined if necessary to protect the metal from corrosion from the contents. Tanks and containers shall be surrounded with a continuous dike or wall capable of effectively holding the total volume of the largest storage container or tank located within the area enclosed by the dike or wall. The construction and composition of this emergency holding area shall prevent movement of any liquid from this area into the waters of the State


Setbacks from the edge of drill pad disturbance o 450 feet from aquatic habitat o 600 feet from special conservation areas o 750 ft setback from downdip side of limestone outcrops to borehole o 2,000 foot setback from a private drinking water well o 1,000 foot setback from the perimeter of a wellhead protection area or source water assessment

area for a public water system for which a Source Water protection Area has been delineated o No well pads on land at an elevation equal to or greater than the discharge elevation of a spring that

is used as the source of domestic drinking water by the residents of the property on which the spring is located, but not to exceed 2,500 feet unless a delineation of the recharge area prepared by a registered geologist, and approved by the Department

Risk Assessment

In a previous section (Drilling Fluid Preparation) it was explained that, for the purposes of this risk

assessment, it will be assumed that there is an 8% likelihood of a spill or leak at every stage of

UGWD. This results in 12 (8% probability x 150 wells) or 36 (8% probability x 450 wells) incidents for

UGWD in Maryland for risk assessment scenarios 1 and 2, respectively. If a release or spill does

occur on the well pad the BMPs proposed by Maryland requiring “zero discharge,” a synthetic liner

over the well pad with decking for protection, an impermeable berm surrounding the well pad

capable of containing 4 inches of rain in a 24 hour period, and transfer of all stormwater collected

on the well pad to storage tanks or trucks as well as the implementation of spill cleanup and

emergency response plans will significantly reduce the potential for these releases or spills to leave

the well pad and contaminate soil, surface water or ground water.

In the event that a storm event over 4 inches in 24 hours overwhelms stormwater capacity, or the

impermeable berm surrounding the well pad fails, any releases or spills that had occurred and not

been cleaned up could result in the transport of drilling fluid additives off the well pad. Maryland’s

Stormwater Design Manual indicates that a rainfall depth of 4 inches for a storm event over 24

hours is just below the threshold for a 10-year storm in Allegany (4.5 inches) and Garrett County (4.3

12

inches) where UGWD in Maryland will be focused (MDE, 2000). The stormwater overflow would

probably cause some soil contamination, but the solution would be significantly diluted by the

stormwater, possibly reducing the impact to soil, surface water and ground water. If stormwater

flow carried spilled chemicals, the setbacks for well pads from private/public water supply and

aquatic habitat and requirement that well pads be constructed on land with a slope less than 15%

would reduce the potential for surface water and ground water contamination. The probability that

drilling fluids would be released to the environment during the mixing of the drilling fluid is

considered low.

Several BMPs have been proposed to minimize the potential impacts from spills. Surface water

contamination on-site and off may occur from major and cumulative minor spills and accidents

involving chemicals use for drilling. Resulting impacts to water quality could adversely affect aquatic

species and recreational activities. Intense and/or sequential storm events could overwhelm

stormwater capacity at the well pad resulting in stormwater runoff and chemicals from prior spills

being discharged into streams and thereby impacting aquatic species and recreational activities. The

consequences associated with soil, surface water or ground water contamination from accidental

releases or spills of drilling fluid additives during drilling fluid preparation will be classified as

moderate as these incidents could have a considerable adverse impact on the environment causing

localized environmental damage. Contaminated surface water could impair water quality at levels

that adversely affect the health of aquatic life and contaminated ground water could impair water

quality in public and private wells at levels that adversely affect human health through water

consumption. For both risk assessment scenarios 1 (150 wells) and 2 (450 wells) the consequences

will be classified as moderate because there could be a considerable adverse impact on people or

the environment in the immediate vicinity and localized or temporary environmental damage.

Impact Assessment: Release during drilling fluid preparation




13

Are drilling fluid

storage containers

properly sealed?

Are drilling fluid additives

released?

Yes

No

Did secondary

containment prevent

release of drilling fluid

additives?

Contamination of soil,

surface water or ground

water

Yes

Yes

Are hoses and fittings

connecting the holding

tanks to mixing apparatus

properly installed,

maintained and operated?

No

No

Yes

No risk to soil,

surface water or

ground water

No

Was spill cleaned up

from soil and before it

could reach ground or

surface water?

Soil Contamination No

No risk to surface

or ground water

No risk to soil,

surface water or

ground water

Yes

Figure 6: Risk flow chart for drilling operations

14

Drilling Operations

Risk Identification

Following site preparation, the drilling operation begins and drilling fluids are pumped from the

storage tanks down the well through the drill string and out the drill bit. The fluids then return to

the surface carrying the drill cuttings and flow to the separation equipment. Following separation,

the drilling fluids are re-circulated back to the storage tanks for reuse. These fluids throughout the

entire drilling operation could potentially be released to the surface due to accidental releases from

line ruptures, leaks, equipment failure, and operational error. These releases have the potential to

contaminate soil, surface water and ground water if they are not properly contained. Drilling fluids

initially entering the well will only contain the chemical additives while the return fluids containing

the cuttings may be contaminated with materials present in the formations through which the

borehole passes. After the drilling fluids are recycled within the closed loop system, the injected

fluids from this point on in the process will also contain these contaminants. The drilling process

takes up to five weeks to complete, including two weeks for drilling the vertical portion and two

weeks for drilling the lateral portion of the well (NYSDEC, 2011).

Drilling occurs in stages in order for casing to be installed and cemented. The drilling fluids that

remain within the borehole are forced to the surface by the cement being injected into the well to

fill the space between the formation and the casing. These fluids return to the surface and are also

recycled within the closed loop system. These fluids could also potentially be released to the

surface due to accidental releases from line ruptures, leaks, equipment failure, and operational

error. These releases also have the potential to contaminate soil, surface water and ground water if

they are not properly contained. In a previous section (Drilling Fluid Preparation) it was explained

that, for the purposes of this risk assessment, it will be assumed that there is an 8% likelihood of a

spill or leak at every stage of UGWD. No additional statistical information specific to accidental

releases during drilling operations was found following an extensive literature search. Based on this

probability, 12 and 36 incidents would occur under risk assessment scenarios 1 and 2, respectively

for all UGWD in Maryland.



ground water from releases during drilling operations:




The term “well pad” is defined to include the areas where drill rigs, pumps, engines, generators, mixers and similar equipment, fuel, pipes and chemicals are located. No discharge of potentially contaminated

15

stormwater or pollutants from the pad shall be allowed. Drill pads must be underlain with a synthetic liner with a maximum hydraulic conductivity of 10-7 centimeters per second and the liner must be protected by decking material. Spills on the pad must be cleaned up as soon as practicable and the waste material properly disposed of in accordance with law. The well pad must be surrounded by an impermeable berm such that the pad can contain at least the volume of 4.0 inches of rainfall within a 24 hour period. The design must allow for the transfer of stormwater and other liquids that collect on the pad to storage tanks on the pad or to trucks that can safely transport the liquid for proper disposal.

Drilling fluids and cuttings must occur in a closed loop system.




area for a public water system for which a Source Water protection Area has been delineated o No well pads on land at an elevation equal to or greater than the discharge elevation of a spring

that is used as the source of domestic drinking water by the residents of the property on which the spring is located, but not to exceed 2,500 feet unless a delineation of the recharge area prepared by a registered geologist, and approved by the Department

Risk Assessment

The probability that a leak or spill during drilling would occur is the same as the probability during

drilling fluid preparation. The probability is considered low.

The drilling fluid that could be released during drilling would differ from the unused drilling fluid in

that it may be contaminated with materials present in the formations through which the borehole

passes. These could include metals and naturally occurring radioactive material (NORM). The

consequence of the release of drilling fluid is classified as moderate because, although it could cause

considerable adverse impact on people or the environment, the damage would be localized. Figure

7 presents a flow diagram for the risk associated with drilling fluid during drilling operations.

16

Impact Assessment: Release from line ruptures, leaks, equipment failure, and operational error




Figure 7: Risk flow chart for drilling operations

Are drilling fluid or return

flows released?

Yes

No

Did secondary

containment prevent


additives?



water

Yes

Yes

Are tanks, hoses and fittings

associated with the closed

loop drilling system properly

designed, installed,


No

No risk to soil,

surface water or

ground water

No




surface water?


No risk to surface

or ground water

No risk to soil,

surface water or

ground water

Yes

No risk to soil,

surface water or

ground water

17

Well blowout during drilling

Risk Identification

A blowout is an uncontrolled flow of gas or other well fluids from the top of the borehole; it occurs

when formation pressure exceeds the pressure applied to it by the column of drilling fluid. Blowout

prevention equipment are devices attached to the top of the well casing that can be closed and shut

off to control pressure at the wellhead. If a blowout occurs it can release formation fluids and eject

casing, tools, and equipment (NYSDEC, 2011). This could cause injury or death to workers on-site

and serious damage to rotary rig equipment. In addition, the formation fluids that are released

under pressure from the well including the cuttings and drilling fluids present in the wellbore would

be ejected, potentially causing contamination of soil, surface water and ground water if not properly

contained. Well blowouts occur very rarely as approximately only 1well will blowout per 1,000 wells

(OGP, 2010).


Current Maryland regulations require that blowout prevention equipment shall be installed at an

early stage of drilling, i.e., before drilling the plug on the surface casing. It must be tested weekly

(COMAR 26.19.01.10Q). These requirements are being retained. In addition, Maryland proposes the

following BMPs that are relevant to protection of the soil, surface water and ground water from

releases during a blowout:

Blowout prevention equipment must have two or more redundant mechanisms

BOPs be tested at a pressure at least 1.2 times the highest pressure normally experienced during the

life of the blow out preventer

Risk Assessment

The probability of a well blowout is low as they rarely occur (approximately 1 well blowout per 1,000

wells). Implementation of the best practices, especially redundant mechanisms and frequent

testing, should further reduce the potential for a well blowout to occur. The likelihood of a blowout

is considered low.

When a blowout occurs, material may be ejected high into the air and it may or may not fall directly

on the pad. A well pad with a four inch berm can contain hundreds of thousands of gallons; it is

likely that the well pad could contain material that falls on it. Material that falls away from the pad

would have to be cleaned up. Setbacks will reduce the chance that material that falls off the pad will

impact surface water or ground water before spill cleanup and emergency response.

18

The material that could be released from a blowout would be similar to the materials that could be

released during drilling. These could include metals and naturally occurring radioactive material

(NORM). The consequences associated with soil, surface water or ground water contamination from

accidental releases of material during a blowout is classified as moderate because, although it could

cause considerable adverse impact on people or the environment, the damage would be localized.

Figure 8 illustrates the pathway for releases of material during a well blowout.

Impact Assessment: Release of material during well blowout




19

Figure 8: Risk flow chart for well blowout

Does well blowout

occur?

Are all the ejected liquids and

solids contained on the well

pad?

No

Surface water or

ground water

contamination

No

Yes

Was material cleaned up


could reach ground water

or surface water?

Soil contamination

Yes

Yes

No risk to soil, surface

water or ground water

No risk to surface water

or ground water

No risk to soil, surface

water or ground water

No

20

Drilling Cuttings Separation, Storage and Transfer for Disposal

Risk Identification

Drilling fluids that return from the well flow to separation equipment in order to remove cuttings

from the fluid for storage and disposal and re-circulate the fluids back to the storage tanks for reuse

in drilling. Separation equipment may consist of shale shakers, de-sanders, and de-silters (NYSDEC,

2011). Additional equipment such as drying shakers, rotary cuttings dryers, squeeze presses or

centrifuges may be required to further separate liquids from cuttings for reuse. The cuttings are

transferred to storage containers and may contain NORM as well as heavy metals and other

chemical contaminants associated with the formation that was drilled. Vertical wells with a total

depth of 7,000 feet will produce approximately 154 cubic yards of cuttings while a horizontal well

with the same target depth and 4,000 foot lateral section will produce 217 cubic yards of cuttings

(40% more) (NYSDEC, 2011). The total volume of cuttings for risk assessment scenario 1 (150 wells)

and 2 (450 wells) would amount to 32,550 cubic yards (217 cubic yards x 150 wells) and 97,650 cubic

yards (217 cubic yards x 450 wells) cubic yards. Because space on a well pad is valuable, it is likely

that cuttings will be disposed of off-site periodically. Cuttings could spill or be released as a result of

failure tanks or containers in the closed loop or during transfer to storage containers.



UGWD. No additional statistical information specific to accidental spills or releases of cuttings on

site during separation and storage was found following an extensive literature search. Based on this

probability, 12 and 36 incidents would occur under risk assessment scenarios 1 and 2, respectively

for all UGWD in Maryland.



ground water from releases of cuttings from the well pad:

Drilling fluid, the returned drilling fluid and the cuttings must be managed in a closed loop system with secondary containment on the well pad.




The term “well pad” is defined to include the areas where drill rigs, pumps, engines, generators, mixers and similar equipment, fuel, pipes and chemicals are located. No discharge of potentially contaminated stormwater or pollutants from the pad shall be allowed. Drill pads must be underlain with a synthetic liner with a maximum hydraulic conductivity of 10-7 centimeters per second and the liner must be protected by decking material. Spills on the pad must be cleaned up as soon as practicable and the waste material properly disposed of in accordance with law. The well pad must be surrounded by an impermeable berm

21

such that the pad can contain at least the volume of 4.0 inches of rainfall within a 24 hour period. The design must allow for the transfer of stormwater and other liquids that collect on the pad to storage tanks on the pad or to trucks that can safely transport the liquid for proper disposal.






Risk Assessment



UGWD. This results in 12 or 36 incidents for UGWD in Maryland for risk assessment scenarios 1 and

2, respectively. A well pad with a four inch berm can contain more than 1,500 cubic yards; it is

therefore likely that the pad could contain any cuttings accumulated on a drill pad. The probability

will therefore be classified as low.

The consequences associated with soil, surface water or ground water contamination from

accidental releases or spills of drilling cuttings during separation and storage will be classified as

moderate as these incidents could have a considerable adverse impact on people or the

environment causing localized damage. For both risk assessment scenarios 1 (150 wells) and 2 (450

wells) the consequences will be classified as moderate. Figure 9 presents a flow diagram of the risk

associated with drilling cuttings separation, storage and transfer for disposal.

22

Impact Assessment: Release of drilling cuttings during separation, storage and transfer for disposal




Are drilling cuttings

released/spilled from

the closed loop

system?

Soil contamination

Was material cleaned up


could reach ground

water or surface water?

No risk to surface

or ground water

Yes

No

No

Did secondary containment

prevent release/spill of

drilling cuttings?

No risk to soil,

surface water or

ground water

Yes

No risk to soil,

surface water or

ground water

No

Low

Pro

babi

lity Yes

Ground water and

surface water

contamination

Figure 9: Risk Flow chart for drilling cuttings separation, storage and transfer for disposal

23

Waste Drilling Fluids Storage

Risk Identification

Used drilling mud is usually not discarded, but rather reconditioned for reuse at a subsequent well

that may be located at the same well pad or a different well pad (NYSDEC, 2011). Following

completion of the drilling operation the waste drilling fluids will likely remain in storage tanks until it

is reconditioned for reuse or shipped off-site for reuse, reconditioning or disposal. While on the

pad, these fluids could potentially be released to the surface due to accidental releases from line

ruptures, leaks, equipment failure, and operational error during the storage period. These releases

have the potential to contaminate surface water and ground water if they are not properly

contained. Marcellus Shale gas wells on average generate 175,000 gallons of waste drilling fluids

per well (Lewis, 2012). The total volume of waste drilling fluids for risk assessment scenario 1 (150

wells) and 2 (450 wells) would amount to 26,250,000 (175,000 gallons x 150 wells) and 78,750,000

gallons (175,000 gallons x 450 wells) for the entire state of Maryland. In a previous section (Drilling

Fluid Preparation) it was explained that, for the purposes of this risk assessment, it will be assumed

that there is an 8% likelihood of a spill or leak at every stage of UGWD. Based on this probability, 12

and 36 incidents would occur under risk assessment scenarios 1 and 2, respectively for all UGWD in

Maryland.



ground water from releases of waste drilling fluid during storage:




24







Risk Assessment

Ina previous section (Drilling Fluid Preparation) it was explained that, for the purposes of this risk


UGWD. This results in 12 or 36 incidents for UGWD in Maryland for risk assessment scenarios 1 and

2, respectively. If a release does occur on the well pad , the pad can contain significantly more than

the 175,000 gallons of waste drilling fluids estimated to be produced per well. Setbacks will reduce

the chance that material that escapes the pad will impact surface water or ground water before spill

cleanup and emergency response

This information indicates that soil, surface water or ground water contamination from accidental

releases of waste drilling fluids during storage will rarely occur if best practices are implemented;

therefore, the probability will be classified as low.

The consequences associated with soil, surface water or ground water contamination from

accidental releases of stored waste drilling fluid are classified as moderate because, although it

could cause considerable adverse impact on people or the environment, the damage would be

localized. Figure 10 presents a flow diagram of the risk associated with waste drilling fluid storage.

25

Impact Assessment: Waste Drilling Fluids Storage




26

Are waste drilling

fluids released

/spilled from storage

tanks or containers?

Soil contamination

Was material cleaned

up from soil and before

it could reach ground

water or surface water?

No risk to surface

or ground water

Yes

No

No

Did secondary containment

prevent release/spill of

waste drilling fluids off the

well pad?

No risk to soil,

surface water or

ground water

Yes

No risk to soil,

surface water or

ground water

No

Low

Pro

babi

lity

Yes

Ground water and

surface water

contamination

Figure 10: Risk flow chart for waste drilling fluid storage

27

Transport of Used Drilling Fluids from the Well Pad

Risk Identification

Used drilling mud is usually not discarded, but rather reconditioned for reuse at a subsequent well that

may be located at the same well pad or a different well pad (NYSDEC, 2011). Waste cuttings will be

transported off site for disposal at an appropriate facility (e.g., industrial waste landfill). Onsite disposal

of cuttings will be prohibited in Maryland if testing shows elevated levels of radioactivity, sulfates,

salinity and other criteria. Vehicular accidents involving trucks transporting these waste materials may

result in their release if the storage tanks containing waste fluids are compromised or rupture, or

containers holding cuttings overturn spilling their contents. These materials could potentially

contaminate ground water or surface water if clean up does not occur in a timely manner prior to

infiltration or leaching into ground water or surface transport during rain events. In addition, if NORM is

present at elevated levels the accidental spill of cuttings could lead to radioactive contamination of

ground water or surface water potentially impacting private or public water supply or aquatic systems.

As previously stated in another section the total volume of waste drilling fluids for risk assessment

scenario 1 (150 wells) and 2 (450 wells) would amount to 26,250,000 and 78,750,000 gallons for the

entire state of Maryland. High-volume capacity options for water hauling trucks vary from about 4,000

to 6,000 gallons (The Gasaway Co. 2002, J&J Truck Bodies & Trailers 2008, Ledwell 2014, Oilmen’s Truck

Tanks 2012). Applying a volume of 5,000 gallons per truck, the total number of truck trips for

transporting waste drilling fluids under risk assessment scenarios 1 and 2, will be 5,250 (26,250,000

gallons / 5,000 gallon truck capacity) and 15,750 (78,750,000 gallons / 5,000 gallon truck capacity),

respectively. As previously stated in the section on Drilling Cuttings Separation & Storage, the total

volume of drilling cuttings for risk assessment scenario 1 and 2 would amount to 32,550 cubic yards and

97,650 cubic yards for the entire State of Maryland. Dump trucks (10-wheel) with a capacity of 10-12

cubic yards can be used to transport drilling cuttings for disposal (B.L. Hayes 2014, Desert Trucking

2014). Applying a volume of 11 cubic yards per truck, the total number of truck trips for transporting

drilling cuttings under risk assessment scenarios 1 and 2, will be 2,960 (32,550 cubic yards / 11 cubic

yard truck capacity) and 8,877 (97,650 cubic yards / 11 cubic yard truck capacity), respectively.

As stated previously in another section of this report there is a 0.005% probability of a hazardous

material cargo spill incident occurring in the U.S. based on information provided by PHSMA. No

information on incidents related specifically to the accidental releases or spills of drilling waste fluids

and cuttings was found following an extensive literature search. While this incidence probability applies

to hazardous material and not hazardous waste transport it will still be applied in determining incident

rates for risk assessment scenario 1 and 2 as no other information was available. Based on an incident

probability of 0.005% under risk assessment scenarios 1 and 2, 0.3 and 0.8 incidents involving the

release of waste drilling fluids during transport would occur, respectively and 0.2 and 0.4 incidents

involving the spill of drilling cuttings during transport would occur, respectively.

28



ground water from releases of waste drilling fluids and cuttings during transportation:


Routes and times of travel shall be established to minimize use conflicts, including school bus transport of children, public events and festivals, and periods of heavy public use of State lands

The permittees must keep a record of the volumes of wastes and wastewater generated on-site, the amount treated or recycled on-site, and a record of each shipment off-site, including confirmation that the full shipment arrived at the facility. The records may take the form of a log, invoice, manifest, bill of lading or other shipping documents

All trucks, tankers and dump trucks transporting liquid or solid wastes must be fitted with GPS tracking systems to help adjust transportation plans and identify responsible parties in the case of accidents/spills

Risk Assessment

The probability of a hazardous material cargo release for a single shipment has been estimated above as

0.005%. This results in 0.3 and 0.8 incidents for all truck trips under risk assessment scenarios 1 and 2

involving the release of waste drilling fluids during transport, respectively and 0.2 and 0.4 incidents

involving the spill of drilling cuttings during transport, respectively. If a release or spill did occur during a

vehicular accident, the probability of soil, surface water or ground water contamination would be


likely to occur because wastes will be tracked by records and by GPS. The probability that materials

would be released during transport is considered low, and the existence of emergency response plans

further lowers the risk that the released material would contaminate soil, surface water or ground

water. The frequency of surface water or ground water contamination from accidental releases or spills

of drilling fluid additives during transport is also considered low on a cumulative basis.

The consequences associated with soil, surface water or ground water contamination from accidental

releases or spills of drilling cuttings during transportation will be classified as moderate as these

incidents could have a considerable adverse impact on the environment causing localized environmental

damage. The consequences associated with soil, surface water or ground water contamination from

accidental releases of waste drilling fluid during transport are classified as moderate because, although

it could cause considerable adverse impact on people or the environment, the damage would be

localized. Figure 11 presents a flow diagram of the risk associated with the transport off-site of waste

drilling fluids and cuttings for disposal.

29

Impact Assessment:




30

Was the spilled material

cleanup up before it reached

soil?

Are waste drilling fluids or cuttings released/spilled from truck? No risk to soil,

surface or ground

water

No

Yes

No risk to soil,

surface or ground

water

No

Soil contamination

Contamination of surface

and/or ground water

No

Yes Was material cleaned up

from soil before it could

reach ground water or

surface water?

No risk to surface or

ground water

Yes Was the spilled material


surface water?

Surface water contamination

No

Yes

Figure 11: Risk flow chart for transport off-site of waste drilling fluids and cuttings for disposal

No No

31

Summary Assessment of Impacts from Drilling Additives, Fluids and Cuttings

Drilling operations for UGWD pose an environment risk due to the potential for accidental releases

or spills of drilling fluids and cuttings during operations on the well pad or off-site during the

transport of drilling fluid additives or waste drilling fluids and cuttings. These accidental releases or

spills have the potential to contaminate soil, surface water and ground water if they are not

properly contained and may occur during the following stages in the drilling process: 1) transport of

drilling fluid additives to the well pad, 2) drilling fluid preparation, 3) drilling operations, 4) well

blowout during drilling, 5) drilling cuttings separation and storage, 6) waste drilling fluid storage, and

7) transport off-site of waste drilling fluids and cuttings for disposal. This risk assessment has

determined that there is low probability for surface water or ground water contamination from

accidental releases or spills in all stages of the drilling process including the transport of drilling fluid

additives and waste drilling fluids and cuttings. The consequences associated with surface water or

ground water contamination from accidental releases or spills was classified as moderate for all

stages of the drilling process except for transport of drilling additives on aquatic life. Human health

could be adversely affected if contaminated ground water impairs the water supply. Aquatic life

could be adversely affected if contaminated surface water or ground water impairs the waterways.

Adverse impacts from direct spills and inappropriate disposal of drillings and cuttings would have

more extensive impacts on aquatic life should they occur in the area of Tier II and Use III waters.

Extensive and perhaps permanent damage would be exacerbated if contamination events occurred

in the headwaters of such streams and in areas where complexes of wetlands and streams provide

significant habitat and support to sensitive aquatic resources (e.g., native Brook trout). In these

cases, the potential downstream impacts and adverse effects to macroinvertebrates and other

sensitive aquatic species could pose problems beyond the localized area of the spills or

inappropriate disposals. The overall risk assessment is summarized in Table 1.

Table 1: Risk Assessment table

Operation Occurrence Environmental Impact

Probability Consequence Risk Ranking

Transport of Drilling Fluid Additives to the Well Pad

Release of drilling fluid additives

Soil, Surface water, Ground water (Human)

Low Moderate Low

Soil, Surface water, Ground water (Ecological

Low Moderate Low

Drilling Fluid Preparation

Release or spill of drilling fluid additives during fluid preparation

Soil, Surface water, Ground water

Low Moderate Low

Drilling Operations

Release of drilling fluids during drilling operation: fluid


Low Moderate Low

32

storage, fluid injection, fluid return, fluid/cuttings separation, & fluid reuse

Well Blowout during Drilling

Release of formation fluids, drilling fluids and cuttings during well blowout


Low Moderate Low

Cuttings Separation & Storage

Spill of cuttings during separation and storage


Low Moderate Low

Waste Drilling Fluid Storage

Release of waste drilling fluids during storage


Low Moderate Low

Transport Off-site of Cuttings for Disposal

Vehicular accidents causing spill or release of drilling waste fluids and cuttings


Low Moderate Low

Transport Off-site of Waste Fluids for Disposal

Vehicular accidents causing spill or release of drilling waste fluids and cuttings


Low Moderate Low


For purposes of this risk assessment, we have assumed that best practices are followed; for

example, that spills are always promptly and completely cleaned up and that accumulated

stormwater is removed from the pad and placed in storage tanks before the pad overflows.

Because accidents and employee errors occur, we recommend two additional measures. First, the

containment capacity of the pad should be increased to contain the precipitation from a 25-year

storm. Initial estimates indicate that this would require increasing the berm height from 4 inches to

5 inches. Second, vacuum trucks should be on standby at the site during drilling, fracturing, and

flowback so that any spills during those stages, which could be of significant volume, could be

promptly removed from the pad.

Sources for Figures Figure 1: <http://www.petrotechsolutions.com/drilling_work-over_completi.html

Figure 2: <http://www.mesawellservicing.com/

Figure 3: <http://www.gn-desander-desilter.com/closed-loop-mud-system/

Figure 4: <http://www.gn-desander-desilter.com/closed-loop-system-for-oil-drilling/

References

Lewis, Aurana. Wastewater generation and disposal from natural gas wells in Pennsylvania. Diss. Duke University, 2012.

B.L. Hayes Trucking & Equipment. “Equipment: Ten Wheel Dump Trucks.” Web. June 2014. <http://www.hayestrucking.com/equip.htm>

Chief Oil and Gas LLC. “Environmental Assessment.” Guard Unit #1H. Drilling application. Prepared by Tri-County Engineering LLC. Dec. 2010.

http://www.petrotechsolutions.com/drilling_work-over_completi.html

http://www.mesawellservicing.com/

http://www.gn-desander-desilter.com/closed-loop-mud-system/

http://www.gn-desander-desilter.com/closed-loop-system-for-oil-drilling/

http://www.hayestrucking.com/equip.htm

33

Chief Oil and Gas LLC. “Environmental Assessment.” PMG Farmer Unit #1H. Drilling application. Prepared by Tri-County Engineering LLC. Jan.

2011.

Craft, Ralph. “Crashes Involving Trucks Carrying Hazardous Materials.” Analysis Brief. Washington, D.C: Federal Motor Safety Administration.

May 2004. <http://www.fmcsa.dot.gov/facts-research/facts-figures/analysis-statistics/fmcsa-ri-04-024.htm.>

Desert Trucking. “Rental Dump Trucks.” Web. June 2014. <http://www.deserttrucking.com/rentaltrucks.html >

FHA (Federal Highway Administration). “Traffic Incident Management in Hazardous Materials Spills in Incident Clearance.” Washington D.C.:

U.S. Dept. of Transportation. January 2009. <http://www.ops.fhwa.dot.gov/publications/fhwahop08058/fhwahop08058.pdf>

International Association of Oil & Gas Producers. Blowout Frequencies. London: OGP, 2010 <http://www.ogp.org.uk/pubs/434-02.pdf>

IPIECA (International Petroleum Industry Environmental Conservation Association). “Drilling Fluids and Health Risk Management: A Guide for

Drilling Personnel, Managers and Health Professionals in the Oil and Gas Industry.” OGP Report Number 396. London: International

Petroleum Industry Environmental Conservation Association, 2009. <http://www.ogp.org.uk/pubs/396.pdf>

J&J Truck Bodies & Trailers. “Specifications & Dimensional Data for Pressure Vacuum Tank Trailers.” 2008. Web. June 2014.

<http://www.jjbodies.com/media/images/site_library/224_Tank_Trailer.pdf>

Ledwell. “5000 Gallon Water Tank.” Web. June 2014. <http://www.ledwell.com/product/detail/5000-gallon-water-tank>


Interim Final Best Practices. (2014):n.pag. July 2014.Web.

<http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf >

---. “2000 Maryland Stormwater Design Manual Volumes 1 & 2.” October 2000.

<http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManual/Pages/Programs/Wate

rPrograms/SedimentandStormwater/stormwater_design/index.aspx>

Oil and Gas Exploration and Production. Division of State Documents. COMAR: 26.19.01. N.p.: 25 November 1991.

Oilmen’s Truck Tanks, Inc. Catalog. 2012. Web. June 2014.

<http://www.trucktanks.com/water-transportation-trucks.htm>

PHMSA (Pipeline and Hazardous Materials Safety Administration). “Hazardous Materials Incident Summaries and Data.” Washington, D.C.: U.S.

Dept. of Transportation. 2014. <http://www.phmsa.dot.gov/resources/data-stats>

---. “Incident Statistics.” Web. <http://www.phmsa.dot.gov/hazmat/library/data-stats/incidents



Reservoirs. Albany: n.p, 2011. PDF file <http://www.dec.ny.gov/energy/75370.html>

NYSWRI (New York State Water Resources Institute). “Spills and Leaks Associated with Shale Gas Development.” Ithaca: Cornell University

Press, 27 April 2012.

http://www.fmcsa.dot.gov/facts-research/facts-figures/analysis-statistics/fmcsa-ri-04-024.htm

http://www.deserttrucking.com/rentaltrucks.html

http://www.ops.fhwa.dot.gov/publications/fhwahop08058/fhwahop08058.pdf

http://www.ogp.org.uk/pubs/396.pdf

http://www.jjbodies.com/media/images/site_library/224_Tank_Trailer.pdf

http://www.ledwell.com/product/detail/5000-gallon-water-tank

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManual/Pages/Programs/WaterPrograms/SedimentandStormwater/stormwater_design/index.aspx

http://www.mde.state.md.us/programs/Water/StormwaterManagementProgram/MarylandStormwaterDesignManual/Pages/Programs/WaterPrograms/SedimentandStormwater/stormwater_design/index.aspx

http://www.trucktanks.com/water-transportation-trucks.htm

http://www.phmsa.dot.gov/resources/data-stats


34

RESI (Regional Economic Studies Institute). “Impact Analysis of the Marcellus Shale Safe Drilling Initiative.” Baltimore: Towson University.

March 2014. <http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/RESI_Marcellus_Shale_Report_Final.pdf

(Accessed June 2014)

The Gasaway Co. 2002. “Water Service.” Web. June 2014. <http://www.gasawayco.com/water.html>

TERC (Transportation Environmental Resource Center). “Reporting Spills.” Web. June 2014.

<http://www.tercenter.org/pages/reportingspills.cfm#haz >

United States Department of Transportation (DOT).” Research and Innovative Technology Administration, Bureau of Transportation Statistics:

Freight Facts and Figures 2013. Web. <http://www.rita.dot.gov/bts/node/493771>

http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/RESI_Marcellus_Shale_Report_Final.pdf

http://www.gasawayco.com/water.html

http://www.tercenter.org/pages/reportingspills.cfm#haz

i

Appendix E:

Fracturing Additives and Fluids

Scope ...................................................................................................................................................................... 1

Chronological Overview of Hydraulic Fracturing Steps .......................................................................................... 2

Transportation of Hydraulic Fracturing Additives to Well Pad ............................................................................... 2

Activity Description ............................................................................................................................................ 2

Activity Duration and Scope .............................................................................................................................. 2

Literature Review of Associated Risks to Surface Water and Ground Water .................................................... 3

Risk Mitigation: Current Regulations and Proposed BMPs ................................................................................ 3

Risk Assessment ................................................................................................................................................. 4

Storage and Handling of Hydraulic Fracturing Additives and Fluid ........................................................................ 6


Activity Duration and Scope .............................................................................................................................. 6

Literature Review of Associated Risks to Surface Water and Ground Water .................................................... 7

Risk Mitigation: Current Regulations and Proposed BMPs ................................................................................ 7

Risk Assessment ................................................................................................................................................. 8

Mixing of Hydraulic Fracturing Additives and Fluid ................................................................................................ 9


Activity Duration and Scope ............................................................................................................................ 10

Risk Assessment ............................................................................................................................................... 10

Fluid Return and Treatment, Recycling and Reuse ............................................................................................... 12

Activity Description .......................................................................................................................................... 12


Literature Review of Associated Risks to Surface Water and Ground Water .................................................. 13

Risk Mitigation: Current Regulations and Proposed BMPs .............................................................................. 14

Risk Assessment ............................................................................................................................................... 15

Transportation of Wastewater off Site ................................................................................................................. 17

Activity Description .......................................................................................................................................... 17


Proposed BMPs Associated with Risk Mitigation ............................................................................................ 17

Risk Assessment ............................................................................................................................................... 17

Summary Assessment of Impacts from Fracturing Additives and ........................................................................ 19


References ............................................................................................................................................................ 21

ii

Figure 1: Hydraulic fracturing totes 2

Figure 2: Risk flow chart for truck transportation of fracturing fluid additives 6

Figure 3: Risk flow chart for storing and handling fracturing fluid additives on drill pad 9

Figure 4: Risk flow chart for mixing fracturing fluid 11

Figure 5: Risk flow chart for fluid treatment, recycling and reuse 16

Figure 6: Risk flow chart for transporting flowback fluids 18

1

Scope

Hydraulic fracturing is a method for extracting hydrocarbons from shale formations. Briefly, the

method entails pumping large volumes of fracturing fluid under high pressure through shale

formations. The movement and pressure of the fluid creates fractures in the shale allowing

hydrocarbons to be accessed. Horizontal directional drilling combined with hydraulic fracturing

techniques has allowed energy companies to access to larger areas of hydrocarbons using

comparatively less surface area.

Fracturing fluid is composed of water and hydraulic fracturing fluid additives. By weight, hydraulic

fracturing fluid additives account for only 1 to 3% of the total weight, approximately 10% is

proppant, and the remaining volume is water (NYSDEC, 2011). The NYSDEC( 2011) cites 10 classes

of additives (including proppant) that have been used in the natural gas in the Marcellus shale

formation:

Acid

Breaker

Bactericide/Biocide

Corrosion inhibitor

Friction reducer

Gelling Agent

Iron Control

Scale Inhibitor

Surfactant

Proppant

Although fracturing fluid additives comprise a relatively small fraction of the total volume of

fracturing fluid, the volume of fracturing fluid needed for a single fracturing fluid operation is

substantial, which makes the total volume of additives needed significant. (Ernstoff & Ellis, 2013;

Rozell & Reaven, 2011). Furthermore, there is not a linear relationship between concentration and

toxicity that can be applied to all chemical compounds. Regardless, there are large volumes of

fracturing fluid additives stored on site at the drill pad during fracturing operations.

Each class of additive may be composed of one or more chemical compounds. These compounds,

and their potential for release into the environment, form the basis for quantifying the

environmental and public health risk caused by hydraulic fracturing.

2

Chronological Overview of Hydraulic Fracturing Steps

Transportation of Hydraulic Fracturing Additives to Well Pad

Activity Description

The hydraulic fracturing process requires large volumes of water and hydraulic fracturing additives.

The revised draft Supplemental Generic Environmental Impact Statement prepared by the New York

State Department of Environmental Conservation (here referenced as New York DEC 2011) states

that fracturing additives are transported in United States Department of Transportation approved

trucks or containers. Fracturing fluid additives are often transported in plastic totes that are loaded

onto flat-bed trucks (Figure 1). These totes are referred to as intermediate bulk containers (IBC).

Other liquid additives that are used in smaller quantities can be transported in one-gallon sealed

jugs carried in the side boxes of the flat-bed truck. Other bulk liquids, such as hydrochloric acid, are

transported in tank trucks. Dry additives, such as proppants, are transported on flat-beds in bags set

on pallets or in plastic buckets (NYSDEC, 2011).

Figure 1: Hydraulic fracturing totes


The duration and scope of this activity would be a function of distance traveled and number of

wells. For the purpose of this risk assessment, it will be assumed that all fracturing fluid additives

will be imported from out of state. NYSDEC (2011) provides estimates for total one way truck trips

per drilling well for fracturing chemicals to be 20 (NYSDEC, 2011). Therefore, under Scenario 1:

3

150 wells * 20 chemical trucks/well = 3,000 loaded chemical truck trips

And under Scenario 2:

450 wells * 20 chemical trucks/well = 9,000 loaded chemical truck trips

If we assume that each truck will travel 100 miles within the state of Maryland and will travel an

average of 50 miles per hour, we can deduce that each loaded chemical truck will be traveling on

roads in Maryland for 2 hours.

Literature Review of Associated Risks to Surface Water and Ground Water

Chemicals being transported can be released into the environment as a result of accidents,

container failure, or other mishaps. Rozell and Reaven (2011) attempted to quantify the relative risk

of chemical spills associated with trucks carrying hydraulic fracturing fluid additives and flowback

water by using data from United States hazmat trucking accidents as a proxy. However, these data

may be underreported. Elsewhere in this risk assessment, using information from the Pipeline and

Hazardous Materials Safety Administration, we estimate that the probability that any single

shipment of hazardous materials would result in a release of hazardous materials to the

environment is 0.005 percent.


Federal regulations (49 CFR Part 178) set minimum standards and integrity testing requirements for

IBCs to ensure that they can withstand normal conditions of transportation. Each IBC must be

manufactured and assembled so as to be capable of successfully passing the prescribed tests. This

testing includes qualifying in the performance of drop, leak-proofness, hydrostatic pressure,

stacking, bottom-lift or top-lift, tear, topple, righting and vibration tests. The specific conditions of

the tests (e.g., drop height) are determined by the physical characteristics of the substance intended

to be transported.

Maryland proposes the following BMPs that are relevant to reducing the risk of accidental fracturing

fluid additives release from trucks:


Encourage local jurisdictions to develop adequate transportation plans, which will be considered in the CGDP process and the review of the transportation plan for the individual permit.

4

The applicant for a well drilling permit must submit a plan that addresses, among other things, road construction and maintenance; and transportation planning, including the identification of routes to be traveled in Maryland by heavy duty trucks and tractor trailers coming to or leaving the pad site

Routes and times of travel shall be established to minimize use conflicts, including school bus transport of children, public events and festivals, and periods of heavy public use of State lands.

Applicants shall be required to enter into agreements with the county and/or municipality to restore the roads which it makes use of to the same or better condition the roadways had prior to the commencement of the applicant’s operations, and to maintain the roadways in a good state of repair during the applicant’s operations. The agreement may mandate that the applicant post bond.

Risk Assessment

The level of risk associated with transporting fracturing fluid additives would also be a function of

the toxicity of the fracturing fluid additives themselves, the volume of fluids being transported, the

distance each truck travels in the state of Maryland, the probability of accidental release in relation

to the distance traveled, and the number of trucks. The predicted distance traveled by each truck

has already been described above.

Quantifying the risk associated with transporting fracturing fluid is difficult. Because the chemical

mixture that composes fracturing fluid is proprietary, there are very few peer reviewed studies that

establish relationships between fracturing fluid concentrations and effects to ecological or human

health. However, Bamberger and Oswald (2012) reported several incidences of live stock health

problems and mortality caused by fracturing fluid release. Furthermore, in a written testimony

before the House Committee on Oversight and Government Reform, Dr. Theo Colborn (2007)

testified that certain chemicals associated with fracturing fluid could cause health problems to

people and wildlife if exposed. Dr. Colborn’s testimony also included an analysis of certain

chemicals used in natural gas development and delivery in Colorado. The report stated that many

chemicals were classified as respiratory toxicants, immunotoxicants, and carcinogens. However, a

specific risk associated with these chemicals cannot be properly quantified because the

concentrations of fracturing fluid chemicals are unknown. If an incident resulted in the release or

spill of drilling fluid additives transporting directly into a stream the contaminated surface water

could significantly impair water quality and adversely affect the health of aquatic life.

The Departments will require the disclosure of all chemicals that the applicant expects to use on the

site. The permittee will be required to provide a complete list (Complete List) of chemical names,

CAS numbers, and concentrations of every chemical constituent of every commercial chemical

product brought to the site. If a claim is made that the composition of a product is a trade secret,

the permittee must provide an alternative list (Alternative List), in any order, of the chemical

constituents, including CAS numbers, without linking the constituent to a specific product. If no

claim of trade secret is made, the Complete List will be considered public information; if a claim is

made, the Alternative List will be considered public information. MDE will retain the list or lists in

the permit file. Each permittee must prepare a site-specific emergency response plan and the

5

permittee must provide a list of chemicals and corresponding Safety Data Sheets to first responders

before beginning operations. MDE must approve the use of any chemical, and will encourage the

use of less dangerous chemicals.

Lacking information regarding the specific fracturing fluid additives that will be used in Maryland, for

purposes of this risk assessment, we will utilize the precautionary principle. For the purposes of this

risk assessment, it will be assumed that fracturing fluid additives are harmful to people and

environmental receptors.

The total amount of additives being transported for a single well can be estimated if we assume that

volume of water needed for hydraulic fracturing is 5,000,000 gallons (41.7 million pounds) and 2%

by weight of the fracturing fluid is fracturing fluid additive. This would equate to approximately

800,000 pounds of additives for each well to be fractured, an amount that could be accommodated

by 20 trucks without violating the limits on gross vehicle weight for multi-axel vehicles. Under

scenario 1, there will be approximately 3,000 truck trips associated with transporting fracturing fluid

additives; under scenario 2, there will be approximately 9,000 truck trips. If the probability of a

release from any one shipment of additives is 0.005 percent, this would equate to less than one

incident under either scenario. The probability of fracturing fluid additive truck accidents is

therefore classified as low.

Soil contamination is likely to be localized and contaminated soil could be removed. This

consequence will be classified as moderate for human impact because it could have an adverse

impact in the immediate vicinity, causing localized or temporary damage. Contaminated ground

water could impair water quality in public and private wells at levels that adversely affect human

health through water consumption.

If an incident resulted in the release or spill of fracturing additives directly into a stream the

contaminated surface water could significantly impair water quality and adversely affect the health

of aquatic life. Damages would be extensive if direct discharges occurred in the headwaters of

streams, particularly in Tier II and Use III streams that support pollution intolerant aquatic life and

native Brook trout populations. The consequences associated with surface water or ground water

contamination from accidental releases or spills of fracturing fluid additives during transport will

therefore be classified as severe for ecological effects. For both risk assessment scenarios 1 (150

wells) and 2 (450 wells) the consequences will be classified as moderate for soil contamination,

ground water and surface water contamination for humans, and severe for ecological effects. Figure

5 presents a flow diagram of the risk pathway for soil, surface water and ground water

contamination associated with the transport of drilling fluid additives to the well pad.

6

Figure 2 describes the risk associated with the transportation of fracturing fluid additives. As shown

in the flow chart, a risk to soil, surface water or ground water would occur if a truck transporting

fracturing fluid additives released the material.

Figure 2: Risk flow chart for truck transportation of fracturing fluid additives

Storage and Handling of Hydraulic Fracturing Additives and Fluid


When fracturing fluid additives arrive at the drill pad, they remain in the totes, containers, and

trucks in which they were transported. When the hydraulic fracturing process begins, the additives

are transferred to a mixing apparatus (NYDDEC, 2011; King, 2012).


Fracturing fluid additives are not delivered to the well pad until fracturing operations are set to

proceed for logistical and economic factors. Therefore, on-site storage time is on average less than

No contamination of

soil, surface or

ground water

No

Yes

No

Surface or ground water

contamination

No

Yes

Yes

ss

Are drilling fluid additives

released during transport?



could reach ground

water or surface

water?

No contamination of

soil, surface or

ground water

Were drilling additives

contained before

reaching the surface?

Soil contamination

No contamination of

surface or ground

water

7

a week and only the amount of additives needed for scheduled hydraulic fracturing operations is

delivered at any one time (NYSDEC, 2011).

The volume of additives on site depends on the amount needed for one well’s fracturing operation,

because it will be assumed that only one fracturing operation will take place at any given time on

the well pad. Therefore, the volume of additives required will be assumed to be 100,000 gallons.


Accidental releases of fracturing fluid additives may occur as a result of failure to maintain

stormwater controls, ineffective surface and subsurface additive fluid containment practices, or

accidental spills. Bamberger and Oswald (2012) reported two cases of hydraulic fracturing fluid

additive spills from storage containers and three incidences of storm water run-off from the drilling

pads.

Chemical components of hydraulic fracturing fluid additives may also be protected by proprietary

licenses. The disclosure of these chemical components to public agencies has therefore been

contentious. A lack of full disclosure to first responders may hinder mitigation and remediation

actions in the event of accidental spills. As noted above, Maryland’s proposed best practices

address this issue.


Maryland proposes the following BMPs that are relevant to reducing the risk associated with

accidental release of fracturing fluid additives during storage and handling at the well pad:

Storage of chemicals in tanks or containers on the well pad with secondary containment





Tanks shall be above ground, constructed of metal or other material compatible with the contents, and lined if necessary to protect the metal from corrosion from the contents. Tanks and containers

8

shall be surrounded with a continuous dike or wall capable of effectively holding the total volume of the largest storage container or tank located within the area enclosed by the dike or wall. The construction and composition of this emergency holding area shall prevent movement of any liquid from this area into the waters of the State


Setbacks from the edge of drill pad disturbance

450 feet from aquatic habitat

600 feet from special conservation areas

750 ft setback from downdip side of limestone outcrops to borehole

2,000 foot setback from a private drinking water well

1,000 foot setback from the perimeter of a wellhead protection area or source water assessment area for a public water system for which a Source Water protection Area has been delineated

No well pads on land at an elevation equal to or greater than the discharge elevation of a spring that is used as the source of domestic drinking water by the residents of the property on which the spring is located, but not to exceed 2,500 feet unless a delineation of the recharge area prepared by a registered geologist, and approved by the Department

Risk Assessment

Because of the requirements for stormwater controls, spill cleanup and secondary containment, it is

judged unlikely that fracturing fluid additives would escape the pad. This risk is therefore

considered to be low. Surface water contamination on-site and off may occur from major and

cumulative minor spills and accidents involving chemicals use for fracturing; Resulting impacts to

water quality could adversely affect aquatic species and recreational activities.

The consequence of soil, surface water or ground water contamination is considered moderate

because although it could cause considerable impact on people or the environment and could affect

the health of persons in the immediate vicinity, the impact would be local.

9

Mixing of Hydraulic Fracturing Additives and Fluid


When hydraulic fracturing procedure begins, pumps and hoses are used to transfer liquid fracturing

additives from holding tanks to a chemical blending unit. Dry fracturing additives are added by hand

into the blending unit. Materials are blended with proppants to form the hydraulic fracturing fluid,

which is immediately pumped into the well bore (King, 2012).

Are fracturing fluid

additives released from

storage containers

Did secondary

containment prevent


additives?



water

Yes

Yes

No

No risk to soil,

surface water or

ground water

No




surface water?

Soil Contamination

No

No risk to surface

or ground water

Yes

No risk to soil,

surface water or

ground water

Figure 3: Risk flow chart associated with storing and handling fracturing fluid additives on drill pad

10


The mixing process takes less than one day. As stated above, the weight of fracturing fluid additives

involved is about 800,000 pounds if additives make up 2 percent of the fracturing fluid and 5 million

gallons of fracturing fluid are needed per well.

Literature Review of Associated Risks to surface water and ground water

There is potential for the accidental discharge of fracturing fluid additives or mixed fluids to the

environment during the mixing process. The primary risk is associated with improper connections

that would allow leaks.

Mixing and pumping of the fluid increases the risk of leaks and spills. Stored fluid is pumped first to

the chemical addition trailer, then to the blender where proppant is added, before going to the high

pressure pumps and down the bore hole. Bamberger and Oswald (2012) surveyed 25 gas wells that

reported accidental releases (e.g. stormwater, wastewater) to ground and/or surface water and

found two cases were fracturing fluid additives were discharged into the environment. In one case

an operational error allowed a chemical blender to discharge fracturing fluid into a cow pasture and

the other involved a defective valve leaking into a goat pasture. King (2012), however, states that

the impacts of spill and leak events are generally low.


The proposed BMPs for reducing the risk of accidental release of fracturing fluid during mixing and

handling are the same as those noted above in connection with reducing the risk associated with

accidental release of fracturing fluid additives during storage and handling at the well pad.

Risk Assessment

The risks associated with mixing fracturing fluid additives primarily relate to the possibility of

releasing fracturing fluid additives while transferring the additives to the mixing apparatus and the

mixing process itself. There is insufficient information to quantify the frequency of improper

installation or failure of hoses and fittings while transferring hydraulic fracturing additives.

Because of the requirements for stormwater controls, spill cleanup and secondary containment, it is

judged unlikely that fracturing fluid would escape the pad. This risk is therefore considered to be

low.

The consequence of soil, surface water or ground water contamination is considered moderate

because although it could cause considerable impact on people or the environment and could affect

the health of persons in the immediate vicinity, the impact would be local.

11

Figure 4: Risk flow chart associated with mixing fracturing fluid additives on drill pad


storage containers

properly sealed?


additives released?

Yes

No

Did secondary

containment prevent

release of fracturing

fluid?

Contamination of


water

Yes

Yes


connecting the holding

tanks to mixing apparatus

properly installed,


No

No

Yes

No risk to soil,

surface water or

ground water

No




surface water?


No risk to surface

or ground water

No risk to soil,

surface water or

ground water

Yes

12

Fluid Return and Treatment, Recycling and Reuse


When the hydraulic fracturing process is completed, the fracturing fluid begins to flow back to the

borehole. The return water is referred to as flowback, produced, or return water. New York DEC

(2011) states that the flowback water components that are of greatest environmental concern are

gelling agents, surfactants, and chlorides. Olmstead et al. (2013) states that the peak flowback

water transport occurs during well fracturing and completion.

The NY EIS states that the reported amount of flowback water recovered in the northern tier of

Pennsylvania ranges from 9 to 35 percent of the total fracturing fluid pumped in. Based on these

percentages, flowback water volume could range from 216,000 gallons to 2.7 million gallons per

well, based on the pumped fluid estimate of 2.4 million to 7.8 million gallons (NYSDEC, 2011). For

the purposes of this risk assessment, 30% flowback will be assumed. This would equate to 1.5-

million gallons of flowback.

Flowback water is generally recovered in two to eight weeks, after which the flowback rate rapidly

declines to about a few barrels a day for the remainder of its production life. In some states,

flowback can be stored in lined pits or in tanks.

Spills or releases result from tank ruptures, piping failures, equipment or surface impoundment

failures, overfills, vandalism, automobile accidents, fires, drilling and production equipment defects,

or improper operations (NYSDEC, 2011).

There may be an economic incentive to reuse flowback water for subsequent hydraulic fracturing

operations, either for the same well pad that produced the flowback water or at a different well pad

(Ernstoff& Ellis, 2013; NYSDEC, 2011; ALL Consulting, 2010). Reuse avoids the need for extensive

treatment or disposal of produced water, helps to lessen demand on freshwater resources, and

lessens the amount of liquid and solid waste. According to the Industry response to information

requests from the New York EIS, companies target 100% recycling of produced water. However,

Rozell and Reaven (2012) found that many operators do not use recycled water due to the cost of

separation and filtration (Arthur & Coughlin, 2008 ; Rozell & Reaven, 2011).

In reality, the chemical components of produced water prevent 100% recycling, but recycling

methods and efficiency are evolving. Operators in the past had used polymers and flocculants to

13

remove metals but more recently filtration technologies have been implemented. The ability to

place a centralized water processing facility for returned water on site can be limited by local

conditions. Steel tanks may be used to store produced water that does not need to be treated and

used for re-use. According to ALL Consulting (2010), current fracturing treatments use between 10%

and 20% recycled fluids, but additives are still required.


The NYSDEC (2011) estimates that the total number of truck trips associated with produced water

disposal to be 100 (NYSDEC, 2011).

A well may continue to produce flowback water for 2 to 8 weeks. There is a wide range of reported

volumes of flowback water, ranging from 30% to 70% of the total injection volume (Ernstoff & Ellis,

2013). King (2012) states that approximately 50% flowback is associated with the Marcellus

formation. Reuse involves either simple dilution or more sophisticated treatment. This treatment

reduces the number of truck trips for hauling waste fluids. But it may also increase the probability

of accidental release or leaks (NYSDEC, 2011).


Potential releases from hoses or pipes used to convey flowback water tanks or a tanker truck and

tank leakage are potential pathways for contamination (NYSDEC, 2011).

Flowback is composed of the fracturing fluids pumped into the well which return up the well to the

surface and produced water, which is water trapped in underground formations that is brought to

the surface during oil and gas exploration and production. The fracturing fluid flowback consists of

water and additives; any new compounds that may have formed due to reactions between

additives; and substances mobilized from within the shale formation due to the fracturing

operation. Produced water from the Marcellus Shale is characterized by its high salinity and total

dissolved solids and may contain a variety of elements such as potassium, calcium, silicon, sodium,

magnesium, tin, sulfur, strontium, zinc, rubidium, arsenic and chromium, some of which exhibit

radioactivity. Produced water can also contain organic compounds, including volatile organic

compounds (VOCs). A recent analysis of Marcellus shale produced water found that the organic

molecules were principally saturated hydrocarbons, with relatively lower levels of aromatic, resin

and asphaltene compounds (Maguire-Boyle & Barron, 2014).. According to ALL Consulting (2010),

the maximum TDS expected in the flowback water ranges from 300,000 to 360,000 mg/L.

Flowback waters are commonly stored in specialized above-ground holding tanks or ponds,

depending on state regulations. A literature review has shown that unintentional discharges from

these storage tanks and ponds have polluted surface waters; however, rates of occurrence have

14

proven difficult to obtain. Ernstoff and Ellis (2013) state that the greatest risk of freshwater

contamination from the process is associated with the storage and handling of return water.

NYSDEC (2011) makes the point that any chemicals that are spilled, including fracturing fluid

additives and fuel, are exposed to rainfall, so that contaminants may be conveyed off-site during

rain events if the site is not properly contained.

When flowback waters are treated at wastewater treatment plants, the treated effluent may

contain high levels of salts and other contaminants, because the treatment processes at many

wastewater treatment plants are not designed to remove them. Olmstead et al. (2013) analyzed

over 8,000 observations to examine relationships among elevated chloride and TSS concentrations

in streams, upstream gas wells pads, and upstream treatment plants that received flowback

wastewaters. The authors found that elevated chloride concentrations were significantly associated

with upstream treatment facilities but not with upstream well pads. Upstream well pads were

significantly associated with elevated TSS but not with elevated chloride concentrations. These

results do not seem to support the idea that spills from upstream wellpad facilities increase chloride

concentrations, but rather contribute to TSS from storm water runoff or during site prep.

Surface water leaks and spills of produced water are associated with shale gas operations (Vengosh

et al., 2014). Analysis has shown that the number of violations is positively correlated with gas

drilling density. Vengosh et al. (2014) deduce that growth and intensity could lead to a higher

probability of surface spill leaks.

In other states, hydraulic fracturing fluid and flowback water have been stored in open pits. Under

normal circumstances, the pit is lined with impervious material that prevents the stored fluid from

migrating to the environment. Bamberger and Oswald (2012) described an incident where the lining

of a storage pond ripped, allowing flowback water to migrate to a livestock drinking water source.

They also cited an incident that involved the dumping of flow back water in a stream that was being

used as a drinking water source for cattle, allegedly causing health problems in the exposed cattle.


In New York, drilling and fracturing fluids and flowback water and production brine are classified as

non-hazardous industrial-commercial waste. This waste classification does not require tracking or

verification (NYSDEC, 2011). Pennsylvania classifies non-hazardous industrial waste, including gas

non-hazardous wastes from drilling as “residual waste” and issues permits to waste handlers and

15

requires transporters to develop contingency plans and submit reports and analyses (PADEP 2014).

Maryland classifies wastes as hazardous or non-hazardous, with no intermediate category.

Maryland proposed the following BMPs that are relevant to the treatment, recycling and reuse of

produced water:

The application for a well permit must include a plan that addresses waste handling, treatment and disposal.

Flowback and produced water shall be handled in a closed loop system of tanks and containers at the pad site. Flowback and produced water may not be stored in surface impoundments or ponds.

Tanks shall be above ground, constructed of metal or other material compatible with the contents, and lined if necessary to protect the metal from corrosion from the contents. Except for tanks used in a closed loop system for managing drilling fluid and cuttings, which may be open to the atmosphere, tanks shall be closed and equipped with pollution control equipment specified in other sections of this report. Tanks and containers shall be surrounded with a continuous dike or wall capable of effectively holding the total volume of the largest storage container or tank located within the area enclosed by the dike or wall. The construction and composition of this emergency holding area shall prevent movement of any liquid from this area into the waters of the State.


Flowback and produced water shall be recycled to the maximum extent practicable. Unless the applicant can demonstrate that it is not practicable, the permit shall require that not less than 90 percent of the flowback and produced water be recycled, and that the recycling be performed on the pad site of generation.


EPA has committed to develop standards to ensure that wastewaters from gas extraction receive proper treatment and can be properly handled by POTWs. EPA plans to propose a rule for shale gas wastewater in 2014. Until these regulations are in place, MDE has requested that POTWs not accept these wastewaters without prior consultation with MDE. MDE does not intend to authorize any POTW facility that discharges to fresh water to accept these wastewaters.

Risk Assessment

The probability that flowback water would be released during treatment, recycling and reuse is not

known. There is a high probability, however, that released flowback water would be contained on

the well pad and not reach the environment. The probability of a release to the environment of

return water is therefore low.

16

The release of flowback water from the drill pad could cause considerable adverse impact on people

and the environment, but the damage would be localized. For this reason, the consequence is

considered moderate. Figure 4 illustrates the course of events that would need to occur to create a

risk to ground water associated with treatment, recycling and reuse of flowback water.

Figure 5: Risk flow chart associated with fluid treatment, recycling and reuse

Are flowback water

containers properly

sealed?

Is flowback water released?

Yes

No

Did secondary

containment prevent

release of flowback

water?

Contamination of

surface water or

ground water

No risk to soil,

surface or ground

water

Yes

Yes


associated with flowback

water treatment and

storage properly installed,


No

No

Yes

No risk to soil,

surface or ground

water

No

Soil Contamination




surface water?

No risk to surface

or ground water

Yes

No

17

Transportation of Wastewater off Site


Flowback water that is not recycled or treated on site needs to be transported to a treatment or

disposal facility. Flowback water is transported in chemical trucks or via pipelines. For the purposes

of this risk assessment, it will be assumed that flowback water will be transported via trucks.


Based on the assumption that each well would produce 30% flowback by volume and none would be

recycled, the total number of truck trips needed to transport waste water would be 300 loaded trips

per well. Based on scenario 1 (150 wells drilled) the total number of truck trips would equate to

45,000. Based on scenario 2 (450 wells drilled) the total number of truck trips would equate to

135,000. Assuming that all these trucks would be transported out of state, the average distance

traveled for each truck would equate to 100 miles.


Maryland has adopted federal Department of Transportation regulations regarding the transport of

hazardous material.

Proposed BMPs Associated with Risk Mitigation

The proposed BMPs that would address releases of flowback during transportation are similar to those listed above, with the addition of the following recommendations associated with reducing the risk of accidental return water release via trucks:


Routes and times of travel shall be established to minimize use conflicts, including school bus transport of children, public events and festivals, and periods of heavy public use of State lands


All trucks, tankers and dump trucks transporting liquid or solid wastes must be fitted with GPS tracking systems to help adjust transportation plans and identify responsible parties in the case of accidents/spills

Risk Assessment

The likelihood of release of hazardous material from any one shipment has been estimated above as

0.005%. Under scenario 1, if none of the return flow were recycled, this would equate to fewer than

3 incidents in which flowback would be released from a truck. Under scenario 2, if none of the

return flow were recycled, this would equate to approximately 7 such incidents. With the

requirement for recycling return flow on site, the number of truck trips and thus the number of

incidents predicted would be reduced by about 90 percent. If a release or spill did occur during a

vehicular accident, the probability of soil, surface water or ground water contamination would be


likely to occur because wastes will be tracked by records and by GPS. The probability that materials

would be released during transport is considered low, and the existence of emergency response

18

plans further lowers the risk that the released material would contaminate soil, surface water or

ground water.

The consequence of the release of flowback/return water is classified as moderate because,

although it could cause considerable adverse impact on people or the environment, the damage

would be localized.

Figure 6: Risk flow chart associated with transporting flowback fluids

Was the spilled material


soil ?

Are flowback wastes released/spilled from truck? No risk to soil,

surface or ground

water

Yes

No risk to soil,

surface or ground

water

No

Soil contamination

Contamination of surface

and/or ground water

No

Yes Was material cleaned up

from soil before it could

reach ground water or

surface water?

No risk to surface or

ground water

Yes Was the spilled material


surface water ?

Surface water contamination

No

Yes

No No

No

NoNo

19

Summary Assessment of Impacts from Fracturing Additives and

Activities associated with hydraulic fracturing have the potential to pose and environmental risk to

ground and surface water via accidental release of fracturing fluid additives themselves or flowback

water. These releases can occur during transportation operations, storage or during the hydraulic

fracturing fluid operation. The risks analyzed in this section have a low probability of occurring

because of regulations that are currently in place and recommended practices that are described in

the BMP document. The consequences of all risks in this process were classified as moderate

because, although they could cause considerable adverse impact on people or the environment, the

damage would be localized. Adverse impacts from direct spills and inappropriate disposal of

hydraulic fracturing additives and flowback water would have more extensive impacts on aquatic life

should they occur in the area of Tier II and Use III waters. Extensive and perhaps permanent

damage would be exacerbated if contamination events occurred in the headwaters of such streams

and in areas where complexes of wetlands and streams provide significant habitat and support to

sensitive aquatic resources (e.g., native Brook trout). In these cases, the potential downstream

impacts and adverse effects to macroinvertebrates and other sensitive aquatic species could pose

problems beyond the localized area of the spills or inappropriate disposals. The risks are

summarized in Table 1.

Table 1: Probability, consequence and risk ranking

Operation Occurrence Environmental

Impact

Risk Risk Ranking

Probability Consequence

Transportation

of Hydraulic

Fracturing

Additives to

Well Pad

Vehicular

accidents

causing release

of fracturing

fluid additives

Soil, surface

water and

ground water

(Human)

Low Moderate Low

Soil, surface

water and

ground water

(Ecological)

Low Moderate Low

Storage and

Handling of

Hydraulic

Accidental spill

of additives

Soil, surface

water and

Low Moderate Low

20

Fracturing

Additives and

Fluid

from well pad ground water

Mixing of

Hydraulic

Fracturing

Additives and

Fluid

Accidental

release or spill

of fracturing

fluid from well

pad additives

during fluid

preparation

Soil, surface

water and

ground water

Low Moderate Low

Fluid Return

and Treatment

Accidental

release or spill

of fracturing

fluid from well

pad additives

during

treatment

Soil, surface

water and

ground water

Low Moderate Low

Transportation

of Flowback

Water offsite

Vehicular

accidents

causing release

of fracturing

fluid additives

Soil, surface

water and

ground water

Low Moderate Low


For purposes of this risk assessment, we have assumed that best practices are followed; for

example, that spills are always promptly and completely cleaned up and that accumulated

stormwater is removed from the pad and placed in storage tanks before the pad overflows. If this

does not occur, however, intense and/or sequential storm events could overwhelm stormwater

capacity at the well pad resulting in stormwater runoff and chemicals from prior spills being

discharged into streams and thereby impacting aquatic species and recreational activities. Because

accidents and employee errors occur, we recommend two additional measures. First, the

containment capacity of the pad should be increased to contain the precipitation from a 25-year

storm. Initial estimates indicate that this would require increasing the berm height from 4 inches to

5 inches. Second, vacuum trucks should be on standby at the site during drilling, fracturing, and

flowback so that any spills during those stages, which could be of significant volume, could be

promptly removed from the pad.

21

References

ALL Consulting. NY DEC Information Requests. Prepared for Independent Oil & Gas Association of New York. 2010. PDF file.

Arthur, J.D., B. Bohm, B.J. Coughlin, and M. Layne. “Evaluating the Environmental Implications of Hydraulic Fracturing in Shale Gas Reservoirs”.

ALL Consulting, 2008.

Bamberger, Michelle, and Robert E. Oswald. "Impacts of gas drilling on human and animal health." New Solutions: A Journal of Environmental

and Occupational Health Policy 22.1 (2012): 51-77.

[Colborn] The Applicability of Federal Requirements to Protect Public Health and the Environment from Oil and Gas Development, 1-22 (2007)

(testimony of Theo Colborn). Print.

Ernstoff, Alexi Sara, and Brian R. Ellis. "Clearing the Waters of the Fracking Debate." Michigan Journal of Sustainability 1 (2013).

King, George E., "Hydraulic Fracturing 101: “What Every Representative Environmentalist Regulator Reporter Investor University Researcher

Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil

Wells." SPE Hydraulic Fracturing Technology Conference. Society of Petroleum Engineers, 2012.

Maguire-Boyle, Samuel J., and Andrew R. Barron. "Organic compounds in produced waters from shale gas wells." Environmental Science:

Processes & Impacts (2014).



<<http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf >



Reservoirs. Albany: n.p, 2011. PDF file.<http://www.dec.ny.gov/energy/75370.html>

Olmstead, Sheila M., et al. "Shale gas development impacts on surface water quality in Pennsylvania." Proceedings of the National Academy of

Sciences110.13 (2013): 4962-4967.

Pennsylvania Department of Environmental Protection (PA DEP). “ Residual Waste Program.” Web. . 2014.

<http://www.portal.state.pa.us/portal/server.pt/community/residual_waste/14093

Rozell, Daniel J., and Sheldon J. Reaven. "Water pollution risk associated with natural gas extraction from the Marcellus Shale." Risk

Analysis 32.8 (2012): 1382-1393.

Specifications for Packagings. 49 Fed. Reg. 178 ( October 1, 2011).

Vengosh, Avner, et al. "A critical review of the risks to water resources from unconventional shale gas development and hydraulic fracturing in

the United States." Environmental Science & Technology (2014)

http://www.portal.state.pa.us/portal/server.pt/community/residual_waste/14093

i

Appendix F

Noise and Visual Impacts.

Table of Contents

Table of Contents .................................................................................................................................................... i

Introduction ............................................................................................................................................................ 1

General Information on Noise ................................................................................................................................ 1

The Effects of Noise on People and the Environment ............................................................................................ 2

Regulation of Noise Levels...................................................................................................................................... 4

Noise Impacts related to UNGD ............................................................................................................................. 5

Anticipated duration of noise-producing activity .............................................................................................. 5

Number of truck trips ........................................................................................................................................ 6

Anticipated noise levels ..................................................................................................................................... 7

Proposed Best Management Practices .............................................................................................................. 8

Visual Impacts Related to UNGD ............................................................................................................................ 9

Impacts .............................................................................................................................................................. 9

Proposed Best Management Practices for Visual Impacts .............................................................................. 10

Risk Assessment ................................................................................................................................................... 11

Phase 1: Site Assessment ................................................................................................................................. 11

Phase 2: Site Preparation ................................................................................................................................ 11

Phase 3: Drilling, Casing and Cementing ......................................................................................................... 12

Phase 4: Hydraulic Fracturing .......................................................................................................................... 13

Phase 5: Well Production Operations .............................................................................................................. 14

Phase 6: Site Reclamation and Well Abandonment ........................................................................................ 15

Summary Assessment of Noise and Visual Impacts ............................................................................................. 15

Suggestions for Additional Mitigation ............................................................................................................. 16

References ............................................................................................................................................................ 17

Table 1: Decrease in noise levels with distance............................................................................................................. 2

Table 2: Community reaction to noise .......................................................................................................................... 3

Table 3: Maximum allowable noise levels ..................................................................................................................... 4

ii

Table 4: Anticipated duration of events ........................................................................................................................ 5

Table 5: Number of truck trips ...................................................................................................................................... 6

Table 6: Truck trips per day ........................................................................................................................................... 7

Table 7: Noise levels at distances .................................................................................................................................. 7

Table 8: Impacts and Assessment: vehicle traffic/thumping/vibration ....................................................................... 11

Table 9: Impacts and Assessment: trucks/traffic/construction noise ......................................................................... 12

Table 10: Impacts and Assessment: drilling noise/vibration ....................................................................................... 12

Table 11: Impacts and Assessment: visual................................................................................................................... 12

Table 12: Impacts and Assessment: traffic noise......................................................................................................... 13

Table 13: Impacts and Assessment: noise from on-site activities ............................................................................... 13

Table 14: Impacts and Assessment: lights ................................................................................................................... 14

Table 15: Impacts and Assessment: noise from truck traffic ....................................................................................... 14

Table 16: Impacts and Assessment: noise from compressors on the pad................................................................... 14

Table 17: Impacts and Assessment: noise from compressors off the pad .................................................................. 15

Table 18: Impacts and Assessment: visual impact from pad ....................................................................................... 15

Table 19: Impacts and Assessment: visual impact from gathering lines ..................................................................... 15

Table 20: Impacts and Assessment: noise from trucks and construction equipment ................................................. 15

Table 21: Impacts and Assessment: visual impact ....................................................................................................... 15

Figure 1: Level of continuous noise causing speech interference. Reproduced from Figure 2.15 (NYSDEC, 2011) ...... 3

Figure 2: Noise levels of vehicles at speed .................................................................................................................... 8

1

Introduction

It is known that a person’s well-being can be affected by noise through loss of sleep, speech

interference, hearing impairment, and a variety of other psychological and physiological factors.

Noise and light may impact domestic animals and wildlife. Visual perception is an important

component of environmental quality. This quality can be adversely impacted if the views seen from

recreational areas, publicly accessible trails, lakes and rivers, scenic highways, scenic vistas, and

other publicly accessible sites are degraded.

This section of the risk assessment evaluates noise and visual impacts from unconventional gas well

development (UGWD). This assessment will outline the duration and magnitude of these impacts at

each step of the shale-gas extraction process. Where information is drawn from published sources,

they are identified. For purposes of this analysis, it is assumed that the best practices detailed in the

Interim Final Best Practices Report (MDE & DNR, 2014) are followed.

The scenarios considered for this risk assessment involve the installation of 150 wells, six on each of

25 well pads, over a ten year period and 450 wells drilled on 75 well pads over a ten year period.

Visual impacts will be evaluated under these scenarios. Noise impacts are more localized and will

likely be experienced at different times and at different locations. Noise impacts will be evaluated

for a single 6-well pad, developed without any pause or interruption. If the wells on a single pad

were drilled and fractured at different times, the noise levels would be similar, but would be

intermittent and extend over a longer time. If two pads were to be developed simultaneously, it

would still be reasonable to evaluate the noise associated with just one because the well pads are

unlikely to be located close together, and noise dissipates with distance. Also, as explained below,

humans do not perceive separate sounds as the sum of the two sounds.

General Information on Noise

The scale for measuring noise intensity is the decibel scale, with a weighted scale (dBA) to account

for relative loudness as perceived by the human ear... Natural nighttime environmental noise levels

in rural areas is commonly estimated to be as low as 30 dBA, depending on weather conditions and

natural noise levels. The noise scale is logarithmic, and an increase of 10 decibels represents a

sound that is 10 times louder; however, humans do not perceive sound this way. A change of 3

decibels is at the threshold of what a person can detect; a 5 decibel change is readily noticeable; and

the human ear perceives an increase of 10 dBA as a doubling of noise levels. (NYSDEC, 2011).

2

The combination of noises is not perceived as the sum of the noises. EPA explained the

phenomenon as follows:

Another unusual property of the decibel scale is that the sound pressure levels of two separate sounds are not directly (that is, arithmetically) additive. For example, if a sound of 70 dB is added to another sound of 70 dB, the total is only a 3-decible increase (to 73 dB), not a doubling to 140 dB. Furthermore, if two sounds are of different levels, the lower level adds less to the higher level. In other words, adding a 60 decibel sound to a 70 decibel sound only increases the total sound pressure level less than one-half decibel (EPA, 1978).

By application of the inverse square law and the logarithmic decibel scale, it can be demonstrated

that a sound level drops 6 dBA for each doubling of distance from the source. (NYSDEC, 2011) The

decrease is shown at various distances in Table 1.

Table 1: Decrease in noise levels with distance

The Effects of Noise on People and the Environment

Elevated noise levels can adversely affect people. Noise can interfere with the ability to understand

speech beginning at a continuous level of approximately 60 dB, as shown in Figure 1.

Distance from source dBA at 25 mph dBA at 50 mph

50 feet 75 83

100 feet 69 77

200 feet 63 71

400 feet 57 65

800 feet 51 59

3

Figure 1: Level of continuous noise causing speech interference. Reproduced from Figure 2.15 (NYSDEC, 2011)

The World Health Organization notes that noise can interfere with sleep by making it more difficult

to fall asleep, causing awakening, altering sleep stages and depth, as well as physiological effects. It

recommends that sound levels should not exceed 30 dBA indoors for continuous noise and 45 dBA

for intermittent noise. (WHO, 2000).

Noise can be annoying, although people differ in their tolerance for noise... A summary of

community reaction to noise is reproduced in Table 2

Ldn (dBA)

Percent Annoyance

Average Community Reaction

General Community Attitude Towards Area

≥75 37 Very Severe

Noise is likely to be the most important of all adverse aspects of the community environment.

70 22 Severe Noise is one of the most important adverse aspects of the community environment.

65 7 Significant Noise is one of the important adverse aspects of the community environment.

60 3 Moderate Noise may be considered an adverse aspect of the community environment.

≤55 Slight Noise is considered no more important than various other environmental factors.

Table 2: Community reaction to noise

4

Source: Table 2.102 (NYSDEC, 2011) original data, Cowan, James P. 1994. Handbook of Environmental Acoustics. New York: Van Nostrand Reinhold.

The noise and other disturbances from seismic testing and drilling operations could cause adverse

impacts to recreational activities in state parks and forests. The recreational experience of anglers,

hunters, and others enjoying outdoor recreation would be adversely affected by noise and light

particularly if it occurs in close proximity to prime fishing locations and during hunting season.

There are large gaps in the existing knowledge and little previous study on the impact of noise on

certain species (FHWA, 2004). Noise can have a significant effect on birds but the impact differs

among species. A study found that noise from a compressor station can impact both the pairing

success and age structure of ovenbirds (Habib, 2007).

Regulation of Noise Levels

The Department of the Environment has promulgated standards for environmental noise; they can

be found in the Code of Maryland Regulations (COMAR) 26.02.03. The standards are goals expressed

in terms of equivalent A-weighted sound levels which are protective of the public health and

welfare. With certain exceptions, a person may not cause or permit noise levels which exceed those

specified in Table 3.

Maximum Allowable Noise Levels (dBA) for Receiving Land Use Categories

Day/Night Industrial Commercial Residential

Day 75 67 65

Night 75 62 55

Table 3: Maximum allowable noise levels

The regulations permit more noise for construction and demolition site activities: 90 dBA during the

daytime hours, and the levels in the table, above, during nighttime hours. In addition, a person may

not cause a prominent discrete tone1 or periodic noise2 which exceeds a level which is 5 dBA lower

than the applicable level listed in the table. The noise standards do not apply to on-road vehicles.

Maryland’s maximum allowable noise levels cannot legally be exceeded. If the applicant’s plan for

complying with the noise standards does not demonstrate that the noise standards will be met, the

permit can mandate additional noise reduction measures. If compliance with the noise standards is

1 "Prominent discrete tone" means any sound which can be distinctly heard as a single pitch or a set of single pitches. For the purposes of this regulation, a prominent discrete tone shall exist if the one-third octave band sound pressure level in the band with the tone exceeds the arithmetic average of the sound pressure levels of the 2 contiguous one-third octave bands by 5 dB for center frequencies of 500 Hz and above and by 8 dB for center frequencies between 160 and 400 Hz and by 15 dB for center frequencies less than or equal to 125 Hz. COMAR 26.03.02.01. 2 "Periodic noise" means noise possessing a repetitive on-and-off characteristic with a rapid rise to maximum and a short decay not exceeding 2 seconds. Id.

5

not verified after operations begin, MDE could issue an administrative order requiring additional

corrective action.

Compliance with this standard is considered protective of public health and welfare; therefore, the

risk to be evaluated for human health is that the standards will be exceeded. The risks to non-

human receptors will be evaluated based on the available literature.

Noise Impacts related to UNGD

Anticipated duration of noise-producing activity

Operation Estimated duration (days) for one event

Estimated duration for one 6-well pad

Access roads 3 - 7 3 - 7

Site preparation (well pad) 7 - 14 7 - 14

Well drilling3 28 - 35 168 - 210

Hydraulic fracturing 2 - 5 12 - 30

Total 40 - 61 190 - 261

Table 4: Anticipated duration of events

Estimates for the duration for one event (Table 6.59) were multiplied by 6 to reflect well drilling and

hydraulic fracturing for a 6-well pad (NYSDEC, 2011). Because only one access road and one well pad

are required for a 6-well pad, the number of days does not increase for a multi-well pad.

Construction of an access road and site preparation would generally occur during daylight hours.

The transportation of equipment, materials, sand, fuel, chemical additives, water and waste

associated with well drilling and hydraulic fracturing could occur anytime of the day or night unless

limited by regulations or permit provisions. Truck traffic is expected to be highest in the last five

weeks of well development, due mainly to the transportation of fluids to the site. (NYSDEC, 2011).

Well drilling and hydraulic fracturing typically continue 24/7 after initiation.

3 More efficient drilling has shortened this time. An industry group represents that drilling a Marcellus shale well can be accomplished in 15 to 30 days. Marcellus Shale Coalition.

6

Number of truck trips

Elsewhere in this risk assessment, the estimated number of loaded, one-way truck trips for a single

well pad with six horizontal wells was estimated as follows in Table 5:

Well Pad Activity All water transported by trucks




Drilling fluids 270 0

Non-rig drilling equipment 90 0



Completion equipment 10 0

Hydraulic fracturing equipment (trucks & tanks) 350 0

Hydraulic fracturing water hauling 6000 0

Hydraulic fracturing sand 138 0

Produced water disposal 1800 0


Miscellaneous 0 400

TOTAL truck trips per 6-well pad 9358 3616

Table 5: Number of truck trips

These numbers assume that 5 million gallons of water are needed to hydraulically fracture each

well, and that 30 percent of that returns to the surface as flowback, but assumes that all flowback is

disposed of off-site. The total number of one-way trips, loaded and not loaded, would be

approximately two times as many, or 18,716 heavy trucks and 7,232 light trucks for the

development of one 6-well pad.

It is difficult to determine the number of truck trips per day or week, but if the assumption is made

that all six wells will be drilled without pause and all six wells fractured immediately after drilling is

complete, it is not unreasonable to assume that the heaviest volume of truck trips would occur as

shown in Table 6:

Delivery of Assumed duration of delivery (days) for six wells on one pad

Number of truck trips per day (one loaded, one empty)

Rig mobilization 5 (190*2) ÷ 5=76

Drilling fluids 30 (270*2) ÷ 30=18

Drilling 30 (300*2) ÷ 30=20

Hydraulic fracturing equipment

5 (350*2) ÷ 5=140

Completion chemicals

30 (120*2) ÷ 30=8

Hydraulic fracturing 30 (6000*2) ÷ 30=400

7

water

Hydraulic fracturing sand

30 (138*2) ÷ 30=9

Table 6: Truck trips per day

Rig mobilization would precede drilling; delivery of drilling fluids and drilling would occur

simultaneously on an as needed basis; hydraulic fracturing equipment would not be delivered until

the drilling was completed and the rig demobilized, and the delivery of completion chemicals,

hydraulic fracturing water and the delivery of sand would follow the delivery of the hydraulic

fracturing equipment and occur simultaneously on an as-needed basis.

The peak period of truck traffic would thus occur during the delivery of completion chemicals and

water and sand for hydraulic fracturing, representing approximately 417 truck trips (one loaded, one

empty) per day. If all the truck trips occurred between 7:00 am and 10:00 pm, the average would be

about 28 truck trips per hour, or one every two minutes during this peak period.

Anticipated noise levels

Information on the noise expected to be produced by the activities used in each phase of horizontal

drilling and HVHF, and the evaluation of the noise at various distances from the source are shown in

Table 7.

dBA at a Distance of (Feet)

Phase 50 250 500 1,000 1,500 2,000

Construction of access road 89 75 69 63 59 57

Well pad preparation 84 70 64 58 55 52

Rotary Air Drilling 79 64 58 52 48 45

Horizontal Drilling 76 62 56 50 47 44

HVHF (20 Pumper trucks operating at a sound level of 115 dBA)

104 90 84 78 74 72

Table 7: Noise levels at distances

Source: Tables 6.54 through 6.58 (NYSDEC, 2011)

According to New York State Department Conservation, “the noise levels generated by vehicles

depend on a number of variable conditions, including vehicle type, load and speed, nature of the

roadway surface, road grade, distance from the road to the receptor, topography, ground condition,

and atmospheric conditions” (2011). Figure 2 shows the noise levels at 50 feet on average pavement

of various types of vehicles and speeds. As can be seen from the figure a heavy truck passing by at

50 miles an hour would contribute a noise level of approximately 83 dBA, while the same truck at 25

miles per hour would contribute about 75 dBA.

8

Figure 2: Noise levels of vehicles at speed

Source: Figure 6.20 (NYSDEC, 2011) (original data from Federal Highway Administration)

The sound from a single truck passing by would exist for a short time, but multiple truck trips along

the same road would result in a higher equivalent continuous noise level (the total sound energy

measured over an hour or other time period) and higher impacts on noise receptors close to main

truck travel routes. (NYSDEC, 2011).

Proposed Best Management Practices

The Best Practices identified in the Interim Final Best Practices report that affect noise are:

The applicant for a permit must submit a plan for complying with the noise standards and for verifying compliance after operations begin.

The Departments will incorporate the concept of “noise sensitive locations” into its review of the CGDP. If “noise sensitive locations” are potentially affected, additional noise controls may be incorporated into individual permits.

The applicant for a permit must submit a transportation plan, including the identification of routes to be traveled in Maryland by heavy duty trucks and tractor trailers coming to or leaving the pad site.

Setbacks from edge of disturbance for well pad

9

o 1,000 feet from the boundary of the property on which the well will be drilled (a waiver can be granted if this is infeasible)

o 450 feet from aquatic habitat o 600 feet from special conservation areas o 1,000 feet from a school, church, or other occupied building (Unless written permission of the

owners is submitted with the application and approved by the Department)

Setbacks of 300 feet from all permanent infrastructure to all cultural and historical sites, State and federal parks, trails, wildlife management areas, scenic and wild rivers, and scenic byways

Setback of 1,000 feet from any compressor station to an occupied building

A power plan that results in the lowest practicable impact from the choice of energy source (If electricity from the grid is available, this would almost certainly mandate the use of electricity in place of diesel-powered drill rigs, compressors, pumps, and generators)

Site-specific noise provisions can be incorporated into individual permits.

The Interim Final Best Practices Report also identifies methods for mitigating noise from drilling and

fracturing operations:

Careful siting of facilities—distance, direction, timing, and topography are the primary considerations in mitigating noise impacts

Placement of walls, artificial sound barriers, or evergreen buffers between sources and receptors (e.g., around well pads and compressor stations)

Use of noise reducing equipment (e.g., mufflers) on flares, drill rig engines, compressor motors, and other equipment

Use of electric motors in place of diesel-powered equipment

Where the initiation of a drilling or fracturing operation or other activities that could be planned in advance or temporarily suspended, scheduling noisy activities to avoid times of peak outdoor recreational periods such as holiday weekends, first day of trout season, and during sensitive wildlife migratory or mating seasons.

Visual Impacts Related to UNGD

Impacts

Perceived visual impacts to scenery and landscape are very subjective: the degradation of the visual

perception of the view. There are no uniform standards for evaluating the visual impact. Local

jurisdiction zoning laws determine the land use allowed within that jurisdiction. The greatest visual

impacts related to UGWD are temporary (roughly 190 to 261 days from construction of the access

road to production). Lights and flares will be visible at night. If wells are being drilled and

hydraulically fractured at different pads that are visible within the same viewshed, the effect will be

more noticeable. The night sky may be less dark. Once the well is in production, however, the visual

impact is less. The pad itself will have well heads and equipment, and pipeline rights of way may

interrupt otherwise unbroken forest, but these impacts are similar to other developed sites and

utility rights of way.

10

Landscape visibility has been demonstrated to be an important variable for wildlife. Elk changed

their behavior in response to natural gas development in Wyoming to minimize their exposure to

roads. (Buchanan, 2014)

Proposed Best Management Practices for Visual Impacts

The Best Practices identified by the Maryland Department of the Environment and the Maryland

Department of Natural Resources (2014) in the Interim Final Best Practices report that affect visual

impact are:

The CGDP will be approved if the State determines that the CGDP conforms to regulatory requirements and, to the maximum extent practicable, avoids impacts to natural, social, cultural, recreational and other resources, minimizes unavoidable impacts, and mitigates remaining impacts

Once an exploratory well has been permitted, no other well, exploratory or production, can be permitted within a 2.5 mile radius around the exploratory well until a CGDP has been approved. Absent a determination by the Department that the exploratory well can be connected to a transmission line without any adverse impact on wetlands, forest, or nearby residents, the exploratory well cannot be converted to a production well until a CGDP for that area is approved.

Location restrictions and setbacks o 1,000 ft setback from well to property boundary of the property on which the well is to be

drilled; a waiver can be granted by the Department if a well location closer than 1,000 feet is necessary due to site constraints

o 1,000 ft setback from edge of drill pad disturbance to a school, church, or other occupied building

o All surface disturbance for pads, roads, pipelines, ponds and other ancillary infrastructure will be prohibited on State owned land, unless DNR grants permission.

o Drill pad location restrictions and setbacks listed in Table 1-1 have been extended to all gas development activities resulting in permanent surface alteration that would negatively impact natural, cultural and historic resources. This includes permanent roads, compressor stations, separator facilities and other infrastructure needs. This expansion applies to aquatic habitat, special conservation areas, cultural and historical sites, State and federal parks and forests, trails, wildlife management areas, wild and scenic rivers and scenic byways

Pre-development environmental assessment should be conducted on a site-specific basis and include, among other things, identification of all ecological, recreational, historical, and cultural resources in the vicinity of a proposed site (includes well pad and all ancillary development such as cleared areas around a well pad, roads, bridges, culverts, compressor stations, pipelines, etc.); and identification of the appropriate setbacks and buffers for the proposed site; and.

Flaring may not be used for more than 30-days on any exploratory or extension wells (for the life of the well), including initial or recompletion production tests, unless operation requires an extension.

Flares shall be designed for and operated with no visible emissions, except for periods not to exceed a total of five minutes during any two consecutive hours.

Night lighting must be used only when necessary for safety, directed downward, and use low pressure sodium light sources wherever possible. Screens or restrictions on the hours of operation shall be required to reduce light pollution further if necessary to minimize conflicts with recreational activities and minimize stress and disturbance to sensitive aquatic and terrestrial communities; provided, however, that hours will not be restricted for activities that are ordinarily carried on continuously once they begin.

Two-stage reclamation will be required: (1) interim reclamation following construction and drilling to stabilize the ground and reduce opportunities for invasive species and (2) post-activity restoration using species native to the geographic range and seed that is certified free of noxious weeds. Pre-development and post-development photographic documentation will be required to ensure site closure conditions are satisfied.

11

The Interim Final Best Practices Report also identifies methods for mitigating visual impacts from

drilling and fracturing operations:

Careful siting of facilities—topography is the primary considerations in mitigating visual impacts

Placement of walls or evergreen buffers between sources and receptors (e.g., around well pads and compressor stations)

Where the initiation of a drilling or fracturing operation or other activities that could be planned in advance or temporarily suspended, scheduling noisy activities to avoid times of peak outdoor recreational periods such as holiday weekends, first day of trout season, and during sensitive wildlife migratory or mating seasons.

Risk Assessment

This section lists the phases of UGWD describes activities; and estimates the probability of excessive

noise and visual impact, as well as the magnitude of the consequence. The probability is rated as

low, medium or high, and the consequence is rated as minor, moderate, or serious. The overall risk

ranking is also stated as Low, Medium, or High.

Phase 1: Site Assessment

Seismic testing, geologic surveys/petro-physical assessments to characterize geologic formations

may be conducted over several weeks, although significant noise is generated only during brief

periods. The testing is done by “thumping” the ground with weight-drop vehicles or by the use of

explosives to generate vibration. Instruments are deployed that register the seismic impact, which

is generally too low to be detected by persons at the surface. Seismic testing requires a permit. Site

assessment may occur in a large area.

The levels of noise and vibration are expected to be low but the noise may be appreciable at close

range. The visual impact is expected to be negligible.


Human Medium Minor Low

Ecological Medium Minor Low

Table 8: Impacts and Assessment: vehicle traffic/thumping/vibration

Phase 2: Site Preparation

A well-pad site is prepared like other construction sites, and is typical of the scale of impacts

associated with any comparable construction activity. It involves clearing and grading, road

building, pit excavation, etc. all with the use of heavy machinery. It will last 7 to 14 days. Equipment

will initially be staged at the site. The activity is more localized than during the Site Assessment

phase. Construction noise is limited to 90 dBA during daytime hours and the setbacks from property

12

lines and occupied buildings should result in sound attenuation sufficient to achieve this standard.

The noise may be appreciable, however.

There will be truck traffic during this phase of the project, with approximately 90 heavy truck trips.

This amount of traffic is not expected to significantly increase noise levels in the community. The

visual impact is expected to be negligible.

Impact on Probability Consequence Risk Ranking



Table 9: Impacts and Assessment: trucks/traffic/construction noise

Phase 3: Drilling, Casing and Cementing

The drill rig itself may be over 100 feet tall and is lighted at night. Drilling entails vertical boring until

the drill bit approaches the target formation, then turning the drill bit and drilling the lateral portion

of the well. Casing and cementing occur during and after the drilling and integrity testing is also

performed. After the casing and cement are in place, the drilling rig is replaced by a temporary

wellhead. As indicated in Figure __, noise levels from drilling should be below 55 dBA at 1,000 feet.

Therefore, the setbacks of the pad from property lines and occupied buildings should result in sound

attenuation sufficient to achieve Maryland noise standards.

Trucks making deliveries to the site are not subject to the noise standards, and there will be

approximately 1700 heavy truck trips during the drilling phase to mobilize the rig and deliver drilling

fluids and other equipment.


Human Low Minor Low


Table 10: Impacts and Assessment: drilling noise/vibration




Table 11: Impacts and Assessment: visual

13


Human Medium Moderate Medium


Table 12: Impacts and Assessment: traffic noise

Phase 4: Hydraulic Fracturing

The well is sometimes prepared for perforation by flushing with acid to remove cement and other

debris. Perforating guns are then placed in the horizontal portion of the borehole, one stage at a

time, beginning at the end of the borehole. The perforating guns fire an array of small explosive

charges that perforate the casing and cement and extend a small distance into the target formation.

Fracturing fluid is then forced down the well into the section under high pressure to create more

fissures in the target formation. These fissures are held open by small particles in the fracturing fluid

called proppant. After each stage is completed, a plug is set and the next stage is perforated and

fractured. Once fracturing is completed the plugs are drilled out and the fracturing fluid begins to

flowback to the wellhead. Water from the target formation, called produced water, also flows up

the well. Flowback and produced water are collected in storage tanks.

The pumps used to generate the pressure for hydraulic fracturing produce a significant amount of

noise, making this stage the loudest. Without noise mitigation, the pumper trucks used in HVHF will

exceed Maryland’s noise standards even at a distance exceeding the mandatory minimum setbacks.

It may therefore be necessary for noise mitigation steps, such as a sound barrier, to be erected at

the pad in order to meet standards. The applicant for a permit must submit a plan for complying

with the noise standards and for verifying compliance after operations begin.

Trucks are not subject to the noise standards, and there will be approximately 16,000 heavy truck

trips during the hydraulic fracturing stage. The probability of harmful noise is high, and the

consequence is considered moderate because it would be localized.




Table 13: Impacts and Assessment: noise from on-site activities

14


Human Moderate Minor Low


Table 14: Impacts and Assessment: lights


Human High Moderate High


Table 15: Impacts and Assessment: noise from truck traffic

Phase 5: Well Production Operations

Well production begins following the completion of the hydraulic fracturing process. Equipment

may be needed on site to remove water from the gas. Gas from the well is transported through

gathering lines to a gas processing plant off-site or to a transmission line. A gathering and boosting

station with a compressor may collect gas from multiple wells and convey it to the processing plant

or transmission line. Compressor stations may also be necessary to pressurize the gas for transport.

Noise from compressors, either on or off the pad, but still within the control of the permittee,

should be sufficiently attenuated by the setback requirements to meet Maryland’s noise standards.

Compressors off the pad that are not under the control of the permittee must meet Maryland noise

standards, but the Federal Energy Regulatory Commission, rather than Maryland, may have

jurisdiction over these compressors.

Impacts and Assessment: noise from compressors on the pad


Human Low Minor Low


Table 16: Impacts and Assessment: noise from compressors on the pad


Human Medium Moderate Moderate


15

Table 17: Impacts and Assessment: noise from compressors off the pad



Table 18: Impacts and Assessment: visual impact from pad



Table 19: Impacts and Assessment: visual impact from gathering lines

Phase 6: Site Reclamation and Well Abandonment

A well is abandoned when it reaches the end of its useful life or is a dry hole. The casing and other

equipment is removed and salvaged; sometimes casing is abandoned in place. Cement plugs are

placed in the borehole to prevent migration of fluids between the different formations. The surface

is reclaimed. The activity is similar to the site preparation stage.




Table 20: Impacts and Assessment: noise from trucks and construction equipment


Human Low Minor Low

Ecological Low Minor Low

Table 21: Impacts and Assessment: visual impact

Summary Assessment of Noise and Visual Impacts

Assuming that best practices are followed, only one risk ranks high for noise and visual impact: noise

from the truck traffic associated with transporting the materials for hydraulic fracturing to the well

pad. Regardless of the final number of well pads in Maryland, noise and visual impacts are expected

to be localized and limited in duration for each site. The probability of impacts of noise due to truck

and equipment traffic is high and will necessarily be more significant if more pads are developed

concurrently and in close proximity.

16


For purposes of this risk assessment, we have assumed that Maryland’s allowable noise levels are

protective of public health and welfare. Sound at lower levels may nevertheless be perceived as

annoying. For this reason, the State should consider a best practice that requires noise reduction

devices on all equipment at the pad site, even if the levels are below the noise standards without

them. For example, all engines and motors could be required to have mufflers. In addition, the

permittee’s plan for bringing water to the site should, to the extent practicable, spread the truck

trips over a longer period of time to reduce the equivalent continuous noise level.

Noise modeling should be required for any drill site that is located within 1,000 feet of any occupied

building to support and verify the permit applicant’s plan for complying with noise standards.

Commercially available software is capable of simulating the three-dimensional movement of sound,

atmospheric and other noise absorption features, and attenuation due to topography. (NYSDEC,

2011).

Consideration should be given to the impact of successive drilling operations in specific areas over

multiple breeding seasons or migration periods to provide long term protection to sensitive species.

17

References

Broderick, John et al. Shale Gas: An Updated Assessment of Environmental and Climate Change Impacts. Manchester: University of Manchester,

2011. < http://www.co-operative.coop/Corporate/Fracking/Shale%20gas%20update%20-%20full%20report.pdf>

Broomfield, Mark. Shale Gas Risk Assessment for Maryland. Ricardo-AEA, 2014. PDF file.

< http://catskillcitizens.org/learnmore/Shale-gas-risk-assessment-for-Maryland_Feb2014.pdf >

Buchanan, Clay B., et al., Seasonal Resource Selection and distributional Response by Elk to Development of a Natural Gas Field, Rangeland

Ecology & Management 67(4): 369-379, 2014.

EPA, Protective Noise Levels: Condensed Version of EPA Levels Document, EPA550/9-79-100, November 1978,

˂http://www.nonoise.org/library/levels/levels.htm˃,

Habib, Lucas, Erin M. Bayne and Stan Boutin, Chronic industrial noise affects pairing success and age structure of ovenbirds Seiurus aurocapilla,

J. of Applied Ecology 44:1 (February 2007)

King, George E. Hydraulic Fracturing 101: What Every Representative, Regulator, Reporter, Investor, University Researcher, Neighbor and

Engineer Should Know about Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells. SPE, 2012.

PDF file.

Marcellus Shale Coalition. “Drilling.” Web. 1 Sept. 2014. <http://marcelluscoalition.org/marcellus-shale/production-processes/drilling/>

Maryland, Environmental Noise Standards. Division of State Documents. COMAR: 26.02.03.02. N.p.: 21 June 2004. Web. Accessed - 1 July,

2014



˂http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf˃



Reservoirs. Albany, NY: Author, 7 Sep. 2011.

"Sound Barriers Guidelines - Highway Traffic Noise." Sound Barriers Guidelines - Highway Traffic Noise. N.p., n.d. Web. 13 Aug. 2014 <

http://roads.maryland.gov/

index.aspx?pageid=827&d=107>

U.S. Department of Transportation (DOT), Federal Highway Administration, Synthesis of Noise Effects on Wildlife Populations, 2004. PDF file.

˂http://www.fhwa.dot.gov/environment/noise/noise_effect_on_wildlife/effects/effects.pdf˃

World Health Organization (WHO). “Guidelines for Community Noise. Geneva: World Health Organization.” 2000. Web.<

http://www.who.int/docstore/peh/noise/guidelines2.html>

http://www.nonoise.org/library/levels/levels.htm

http://marcelluscoalition.org/marcellus-shale/production-processes/drilling/

http://roads.maryland.gov/index.aspx?pageid=827&d=107

http://roads.maryland.gov/index.aspx?pageid=827&d=107

http://www.fhwa.dot.gov/environment/noise/noise_effect_on_wildlife/effects/effects.pdf

http://www.who.int/docstore/peh/noise/guidelines2.html

i

Appendix G

Water Withdrawal

Scope ...................................................................................................................................................................... 1

Background ........................................................................................................................................................ 1

Relevant steps in the process of unconventional gas well development ............................................................... 1

Risks identified ....................................................................................................................................................... 2

Potential impacts to local and regional water supplies ..................................................................................... 2

Potential impacts to ecological systems and aquatic species in rivers and streams ......................................... 2

Potential impacts on recreational activities ...................................................................................................... 3

Factors influencing risks of UGWD-related water withdrawals ......................................................................... 4

Western Maryland’s water supply ......................................................................................................................... 4

Risk Mitigation: Current regulations and Proposed BMPs ..................................................................................... 5

Existing regulatory framework .......................................................................................................................... 5

Recommended Best Practices ........................................................................................................................... 6

Evaluation of risks ................................................................................................................................................... 6

Impacts from water withdrawal for drilling (Phase 3) ............................................................................................ 8

Impacts from water withdrawal for hydraulic fracturing (Phase 4) ....................................................................... 9


References: ........................................................................................................................................................... 12

1

Scope

This section evaluates risks from the withdrawal of water for use in unconventional gas well

development (UGWD). The specific focus of this section is water withdrawal, rather than subsequent

storage, use and reuse of the withdrawn water, which are considered in other sections.

Background

Large quantities of water are required for UGWD, particularly during high-volume hydraulic fracturing

(HVHF). According to an estimate for UGWD in the Pennsylvania portion of the Susquehanna River basin,

fresh water withdrawals from permitted surface water sources are typically used, and the next most

significant source is purchase from public water systems (Abdalla, 2011). Other potential water sources

include on-site groundwater resources and treated waste water. Literature sources estimate that 2-5

million gallons of water are usually required for each well through completion of HVHF, and note that

total water volumes depend on factors such as well depth, length of laterals, and number of HVHF

stages (Nicot & Scanlon, 2012; Ernstoff & Ellis, 2013). Permit applications received by the Maryland

Department of the Environment (MDE) in 2009-2012 estimated daily water usage of 20,000 gallons per

well during well drilling and total water usage of 3-7 million gallons per well for HVHF.

As noted below, this assessment assumes that an average of five million gallons of water is required for

each well through completion of HVHF.

Fresh water demands may be reduced by on-site water reuse, technological advances which improve

efficiency of water use during hydraulic fracturing, and, where possible, use of alternatives such as

brackish water (NGWA, 2014).

Relevant steps in the process of unconventional gas well development

Phase 3: Drilling Phase

Phase 4: Hydraulic Fracturing

2

Risks identified

Potential impacts to local and regional water supplies

Surface water and ground water provide essential supplies for drinking water, agriculture, ecological

resources, recreation and some commercial and industrial activities. At a local or regional level, water

demands for UGWD could reduce availability of fresh water for existing uses as well as prospective uses.

Because water may be transported to pads from off-site sources at varying distances, even from out of

state, these local effects could occur anywhere. Water withdrawals could also make a particular water

supply more vulnerable to impacts during and after drought conditions. These risks are not specific to

UGWD. Unlike many other water uses, however, most of the water withdrawn for HVHF is removed, not

only from downstream users, but from the water cycle. The compressed time frame of water demands

for unconventional gas wells generally result in companies utilizing on site storage to meet the peak

demands. Thus, it is important to know not only the total volume of water needed but the actual rate of

withdrawal to identify potential risks on water supplies.

Potential impacts to ecological systems and aquatic species in rivers and streams

Water withdrawals for unconventional gas well development could pose a range of risks for direct and

indirect impacts to ecological systems in rivers, streams, wetlands, springs and seeps by reducing flow

and related effects. Water withdrawals from surface and groundwater systems can adversely affect

aquatic ecosystems. Changes in water levels and streamflow regimes affect the quantity and quality of

stream habitat, water chemistry (temperature, DO), and critical life history periods (spawning). These

cumulative effects from hydrologic alteration on the composition of stream assemblages are well

documented in a variety of hydrologic and ecological systems (Dewson et al., 2007; Bradford &

Heinonen, 2008; Poff & Zimmerman, 2010). Numerous examples were reviewed generally within an

exhaustive literature review on flow-ecology alteration relationships and specifically as they related

management of the hydroecological integrity of Maryland’s streams (Ashton, 2013). Carlisle et al.

(2011) reported that increasing deviation from expected minimum flows resulted in a higher proportion

of biological impairment. Experimental reductions in stream flow resulted in fewer invertebrates,

insects, and EPT (Ephemeroptera, Plecoptera and Trichoptera) taxa compared to an unaltered stream

(Wills et al., 2006). Large, consumptive water uses in the Great Plains have been responsible for major

shifts in fish assemblages and are projected to substantially fragment and reduce habitat under current

withdrawal scenarios (Gido et al., 2010; Falke et al., 2011). In a recent study in the New Jersey Pinelands,

Kennen et al., (2014) found that modeled reductions in groundwater through increased withdrawals

would result in degradation of the macroinvertebrate community. In a large spatial analysis of Maryland

Biological Stream Survey and water withdrawal data, a negative relationship was observed in several

biological metrics and the abundance of select fish species as the magnitude of water withdrawal

increased within a watershed. In that preliminary analysis, the effect of flow alteration was not readily

distinguishable from other natural (stream size) or anthropogenic (urbanization) variables; however,

that was not a goal of the study.

3

Literature sources also note the uncertainty of flow-ecology relationships and that consideration of

single biological or hydrological end points are not sufficient to maintain healthy, functioning aquatic

ecosystems (Lytle & Poff, 2004; Arthington et al., 2006). Rapid expansion of natural gas development

may pose a threat to surface waters, and it is inadvisable to allow large consumptive withdrawals in

watersheds of streams with valuable natural resources (e.g., Use-Class IV, Tier II, protected species, etc.)

(Entrekin et al., 2011).

Risks to ecological systems and aquatic species may come from direct withdrawals of water from rivers

or streams, or from withdrawals of ground water that feeds rivers or streams (Ernstoff & Ellis, 2013;

NGWA, 2014). Ecological systems and aquatic species in rivers and streams that are sensitive to low-flow

or drought conditions would be most vulnerable to these impacts, particularly if high volumes of water

are withdrawn over relatively short time periods. Water quality impacts could include changes in

temperature, oxygen levels and flow rates that would adversely affect aquatic species. For example, if

surface water sources are utilized, there is potential for adverse impacts to mussel species. Brook trout

populations are limited by stream flow and water temperature (Heft et al., 2006), particularly during the

summer and fall seasons. In Maryland, these seasons coincide with the lowest annual flow rates and the

highest annual water temperatures. Published literature describes the negative impacts of reduced flow

and increased water temperatures on brook trout life history needs, survival, growth, reproduction, and

population levels (Hakala & Hartman, 2004). Currently, brook trout populations in Maryland are

extremely fragile, with less than 40% of historic habitat still occupied, and the majority of these

populations are at extremely reduced levels. The experience of resource professionals including

Maryland Department of Natural Resources (DNR) biologists and the currently available literature

suggests that surface and/or groundwater withdrawals have the potential to impact not only the

hydrology of Maryland's brook trout streams, but also limit the ability of Maryland’s existing brook trout

streams to support brook trout (Weltman-Fahs & Taylor, 2013). Furthermore, special concern should be

paid to potential water withdrawals in low-flow periods (typically during summer months) because

many of Maryland's brook trout streams are close to exceeding maximum temperature tolerances for

brook trout during this period. Weltman-Fahs and Taylor (2013) suggest that further decreasing flows

for water withdrawals during this time will limit the amount of habitat available to not only fish, but

many other aquatic organisms as well. Reducing flow during this critical period has the effect of further

increasing temperature due to increased exposure of bottom substrate to sunlight. Higher water volume

can buffer this effect and prevent reflective heat from warming the water, but at low flows the heat

impacts the bottom and more readily transfers into the water column resulting in increased water

temperatures and lower dissolved oxygen. Conversely, low flows during the winter increases the risk of

anchor ice forming which can cause reproduction failure for trout and other finfish in shallow streams.

Potential impacts on recreational activities

The lakes, streams and rivers of western Maryland are heavily used for boating, fishing, swimming and

other water-related activities. In the case of Deep Creek Lake, the demand for water for snow-making,

4

boating and fishing compete with each other and power generation. The water appropriation permits

for Deep Creek Lake have been written to balance these competing needs. The competing uses for any

water resource should be considered in developing a water appropriation permit.

Factors influencing risks of UGWD-related water withdrawals

Risks to water supplies from water withdrawals will depend on multiple factors, including baseline

characteristics and status of individual water supplies, connections and relationships between water

supplies, existing uses of the water supplies, and whether one or more related water supplies serve as

the common supply for development of multiple gas wells. Additional considerations include the timing

of gas well development and the variability of water demands. Since large volumes of water are not

required after HVHF has been completed, water demands for individual gas wells will be temporary.

However, staggered development of multiple gas wells using a common water supply would increase

the duration of water withdrawals when compared to that required for an individual gas well. Water

availability may be particularly impacted if withdrawals from a common water supply for convergent

demands of multiple gas wells coincide with peak demands from other uses of the same water supply

(Nicot & Scanlon, 2012). Additionally, water needs for unconventional gas wells may vary over space

and time, even within the same geographic area (Nicot & Scanlon, 2012), so it may be difficult to predict

water demands in a scenario where multiple gas wells rely upon a common water supply that, in turn,

supports other competing uses. The above considerations would also interact with precipitation status,

changes in population, and changes in land use.

Western Maryland’s water supply

In the potential productive portion of the Marcellus Shale region in Maryland (Garrett County and

western Allegany County) the population relies on private wells and springs, community water supply

wells and springs, and withdrawals by community water systems from streams, rivers and reservoirs. An

estimated two thirds of Garrett County residents (21,000) obtain water from individual groundwater

supplies. Groundwater is also the primary supply for public water systems in Garrett County, accounting

for service to about 6,400 of the 9,200 residents served by community water systems. There are a total

of 15 community water systems in Garrett County. The largest serves the Town of Mountain Lake Park

and the smallest serves a small mobile home park.

In contrast, Allegany County residents are more likely to receive water from a public water system. More

than 90% of the County’s population is served by a public water system. A significantly higher

percentage of the County’s population (85%) is estimated to be served from a surface supply. Several

communities in Allegany County obtain their water from withdrawals in Garrett County (Frostburg,

Westernport and a portion of Midland Lonaconing’s supply). Water from the City of Cumberland serves

many of the surrounding areas.

5

Significant non-potable uses include, in descending order: withdrawals for hydroelectric generation

(from Deep Creek Lake); manufacturing (such as the paper mill in Luke); mine dewatering

(predominantly coal); releases to support cold water fisheries, and fish hatchery operation. As noted

above, recreational uses (e.g., golf course irrigation, snow making, white water rafting, boating and

fishing) are also among the important non-potable uses that might be impacted by water withdrawal for

UGWD.

Risk Mitigation: Current regulations and Proposed BMPs

Existing regulatory framework

Maryland laws and regulations governing water withdrawals are designed to protect water supplies and

the users of water supplies. Specific consideration is given to aggregate changes and cumulative impacts

in the context of both current and future appropriations in a given area. Water appropriation permits

are required for any activity that withdraws water from the State’s surface waters or ground waters,

unless the specific activity is exempted from the permit process. Withdrawals of groundwater less than

5,000 gallons per day, as an annual average, are exempted if certain criteria are met. Withdrawals of

more than 10,000 gallons per day, as an annual average, may require detailed analyses, such as aquifer

testing, as part of the permit application.

Water appropriation permits include specific limits that are intended to prevent excessive water

withdrawals, including withdrawals over a short time period. All groundwater permits have two limits;

these include an annual average and a daily average during the month of maximum use. Withdrawals of

surface water also have two limits: these are an average annual limit and a maximum day limit. Impacts

to other uses are evaluated based on peak withdrawal rates. A permit may contain a condition requiring

the permittee to stop or reduce water use when directed to do so by the Department during a drought

period or emergency. The Department may condition approval of a surface water appropriation or use

permit on the permittee's provision of low flow augmentation to offset consumptive use during low flow

periods to protect other users of the water and to protect the resource. A surface water appropriation

or use may be conditioned on the maintenance, by the permittee, of a required minimum flow past the

point of appropriation to protect other users of the water and to protect flora and fauna within the

watercourse; new surface water permits have screening requirements (1 millimeter) and intake velocity

requirements (0.5 feet per second) to minimize potential of the withdrawal for removing or harming

small fish, fish eggs or other small aquatic organisms.

Water appropriation regulations can be found in the Code of Maryland Regulations, Title 26, Subtitle

17.06 (COMAR 26.17.06).

6

Recommended Best Practices

The Best Practices report states that water sufficient for HVHF could likely not be obtained without a

water appropriation permit, considering the relatively small amount of water withdrawal that would

require a permit (MDE & DNR, 2014, pp. 31-32). The report also notes that MDE and DNR feel that

existing criteria used to evaluate water appropriation applications are adequate to address water

withdrawals for UGWD (MDE & DNR, 2014, p. 32). In addition, a generalized water appropriation plan

will be required for the Comprehensive Gas Development Plan (CGDP) that identifies the proposed

locations and amounts of water withdrawals needed to support the plan. MDE will use this information

to identify any proposed appropriations that may not be granted due to supply, environmental, public

health or other restrictions, and will allow the applicant to revise the CGDP.

Proposed BMPS that would address potential impacts from UGWD-related water withdrawals are

outlined below.

An invasive species plan is required for drill permits to prevent introduction of any invasive species, including pathogens.

Includes a survey for invasive species must be done at water withdrawal sites.

Contains procedures for avoiding transfer of species by clothing, boots, vehicles, water transfers, restoration materials, etc.

Avoids using waters from areas known to have invasive species present.

Recycling to reduce water appropriation needs

90% of flow back and produced water to be recycled unless applicant can demonstrate that it is not practicable

To occur on the pad site of generation

Evaluation of risks

Table 1 and Table 2 in Section IV present two potential scenarios for UGWD in Maryland. Scenario 1

assumes 25% extraction with 150 total wells drilled, an average of 15 new wells per year, and a range of

6-29 new wells per year. Scenario 2 assumes 75% extraction with 450 total wells drilled, an average of

45 wells drilled per year, and a range of 12-72 new wells per year. The following figure presents

estimates of water volumes required for UGWD under each scenario, using the assumption of five

million gallons of water per well:

7

Figure: Estimates of total water demand for UGWD in Western Maryland

SCENARIO 1 (25% EXTRACTION)

Estimate based on average number of new wells per year:

15 new wells per year x 5 million gallons per well = 75 million gallons per year

Estimate based on maximum number of new wells per year:


SCENARIO 2 (75% EXTRACTION)

Estimate based on average number of new wells per year:


Estimate based on maximum number of new wells per year:


Under Scenario 2, the estimated volume of water required during the year with the highest number

of new wells is 360 million gallons, or 0.99 million gallons per day (mgd) as an annual average. If all

of this water were withdrawn over a six month period, the corresponding volume would be

approximately 1.98 mgd. The following are included to place these volumes into a regional context

for water use and availability:

The largest public water system in the region is the City of Cumberland, which withdraws water from Pennsylvania. According to an MDE Water Management Administration database, this system’s average use is about 2.5 mgd and the plant design is about 15 mgd.

The largest streams in the area where UGWD would be expected to occur are the Youghiogheny River and North Branch of the Potomac River. A table of mean monthly flows at the North Branch and Friendsville gage is available from the web interface of the U.S. Geological Survey’s National Water Information System. This interface presents monthly data in cubic feet per second and is available at http://waterdata.usgs.gov/nwis/. Using a conversion of 1 mgd = approximately 1.54 cubic feet per second, the lowest recorded monthly flow for the Friendsville gage since 1990 is 49.8 cubic feet per second, or 32.3 mgd, in September 1991. The lowest value since 2005 is 69.4 cubic feet per second, or 45.1 mgd, in September 2010. Under Scenario 2, water demands for UGWD during the year with the highest number of new wells (approximately 1.98 mgd if all activity took place during six months) would represent 6.1% of the flow recorded in September 1991 and 4.4% of the flow recorded in September 2010.

During a year with average precipitation, over 1.3 billion gallons of water falls on Garrett County, on average, each day (MDE & DNR, 2014).

At the level of a single unconventional gas well, risks related to water withdrawal are generally expected

to be low and infrequent (Ricardo, 2013). The New York State Revised Draft Supplemental Generic

Environmental Impact Statement states that, on an individual basis, the impact from water withdrawal is

low, and estimates that even the cumulative withdrawal at peak HVHF activity would increase statewide

http://waterdata.usgs.gov/nwis/

8

fresh water demand by only 0.24% (NYSDEC, 2011, p. 6-10). However, a statewide estimate may not

reflect local impacts, and the implications of this estimate would not necessarily apply in Western

Maryland. Even a single well could pose risks if it uses water that is withdrawn from an already-stressed

water supply, particularly if HVHF-related withdrawals coincide with other factors such as drought or

peak demand from competing uses. Furthermore, habitat and sensitive species that are particularly

dependent on a certain water supply could be impacted from water withdrawals for even one well.

The overall level of risk associated with water withdrawals could be highly variable since it will be based

on specific local conditions. However, Maryland’s current water appropriation regulations and

permitting process should serve to reduce the impact of water withdrawals, particularly because of

consideration of aggregate changes and cumulative impact for both current and future appropriations.

Attention to key factors will be necessary to prevent or reduce impacts to local water supplies,

ecological systems and sensitive aquatic species, and recreational activities. These include a)

consideration of the real-time water demands of HVHF as they relate to other uses and to impacts on

habitat and sensitive species; and b) integration of existing knowledge with consideration of

unpredictable conditions in order to inform the appropriations process. Additionally, the recommended

best practice of the CGDP for multiple-well planning could help identify risks associated with water

withdrawals. CGDPs could provide early insight into concerns and problems that will be raised during

the permit application process, including the cumulative impacts on water supply from existing and

proposed appropriations.

While the anticipated impacts from UGWD-related water withdrawals are likely to be variable, the

probability and consequence framework presented in Figure 1 (Section III of the core document) can be

used to consider these potential impacts during UGWD phases relevant to water withdrawal. The

following findings assume that a) the existing regulatory framework is in effect, and b) the above BMPs

may serve to avoid or minimize the adverse impacts discussed above:

Impacts from water withdrawal for drilling (Phase 3)

The probability of adverse impacts to local and regional water supplies, ecological systems and aquatic

species, and recreational activities is expected to be low. If adverse impacts occur, the consequences are

expected to be minor.

Rationale for findings: The existing water appropriation permitting process considers current and future

cumulative impacts of water withdrawals and is expected to prevent excessive withdrawals during well

9

drilling, so the probability finding is low. Impacts that occur despite the permitting process are expected

to be of minor consequence because relatively modest volumes of water are required for drilling.

Impacts from water withdrawal for hydraulic fracturing (Phase 4)

The following findings apply to multiple-well scenarios with staggered well development, where HVHF of

multiple wells may occur simultaneously with drilling of multiple wells.

Impacts to local and regional water supplies: The probability of adverse impacts to local and regional

water supplies is expected to be low. If adverse impacts occur, the consequences are expected to be

moderate.

Rationale for findings: The existing water appropriation permitting process considers aggregate changes

and cumulative impacts in the context of both current and future appropriations, and permits include

both daily and annual limits on average withdrawal volumes. The permitting process is expected to

prevent excessive withdrawals that could impact local and regional water supplies, including high-

volume withdrawals over a relatively limited time period, so the probability finding is low. Additionally,

implementation of area-specific CGDPs for multi-well planning should provide valuable input for

consideration of cumulative impacts from water withdrawal. Because large volumes of water are

required for HVHF, impacts that occur despite the permitting process have the potential to be of

moderate consequence to other uses of local and regional water supplies.

Impacts to ecological systems and aquatic species: The probability of adverse impacts to ecological

systems and aquatic species is expected to be moderate. If adverse impacts occur, the consequences are

expected to be moderate.

Rationale for findings: Some aquatic species may be sensitive to relatively minor decreases in water

levels or flow which would not otherwise cause appreciable impacts on local and regional water supplies

or recreational activities, so the probability finding is moderate. Similarly, impacts that occur despite the

permitting process could be of moderate consequence to aquatic species. If withdrawals occur in the

headwater areas of Use Class III streams and Tier II waters, impacts have the potential to be of serious

consequence to aquatic species.

10

Impacts on recreational activities: The probability of adverse impacts on recreational activities is

expected to be low. If adverse impacts occur, the consequences are expected to be moderate.

Rationale for findings: Consideration of current and future cumulative impacts in the existing water

appropriation permitting process is expected to prevent impacts to recreational activities, so the

probability finding is low. Because large volumes of water are required for HVHF, impacts that occur

despite the permitting process are expected to be of moderate consequence to recreational activities.

These findings are also presented in the Table 1 and Table 2 below. The rightmost column includes the

Risk Ranking, which combines the probability and consequence findings into a single finding according to

the matrix in Section III of the core document.

Table 1: Probability, consequence and risk findings for drilling (Phase 3)


Local and regional water supplies Low Minor Low

Ecological systems and aquatic species Low Minor Low

Recreational activities Low Minor Low

Table 2: Probability, consequence and risk findings for hydraulic fracturing (Phase 4)


Local and regional water supplies Low Minor Low

Ecological systems and aquatic species Medium Moderate Medium

Recreational activities Low Moderate Low


The following measures could be considered in order to reduce risks from UGWD-related water

withdrawals beyond the anticipated protections of the existing regulatory framework and the

proposed BMPs:

1. Each Maryland county providing water for UGWD establishes one or more semi-permanent access points for UGWD-related water withdrawals at a source with large capacity. County access points could reduce risks by allowing focused implementation of the regulatory framework and targeted monitoring for withdrawal-related impacts. It would also reduce the risks associated with withdrawals from smaller streams. If storage is provided, water could be accumulated over time and could facilitate the use of a pipeline to transfer water.

11

2. Require that applicants obtain third-party modeling of affects of withdrawals proposed for Tier II and

Use III waters, using protocols to be developed by DNR. The purpose of this requirement would be to provide data necessary to evaluate the potential impacts to aquatic habitat and species as well as downstream recreational activities.

3. Ecological and/or recreational protection needs are identified by the Maryland Department of Natural Resources for consideration in the water appropriation permitting process. The existing regulatory framework could be strengthened by requiring specific identification of potential impacts to ecological systems by DNR, so that those potential impacts can be explicitly addressed.

12

References: Abdalla, Charles, et al. "Water’s Journey Through the Shale Gas Drilling and Production Processes in the Mid-Atlantic Region." Penn State

Extension: College of Agricultural Sciences, Pennsylvania State University (2012). ˂http://extension.psu.edu/natural-

resources/water/marcellus-shale/regulations/waters-journey-through-the-shale-gas-drilling-and-production-processes-in-the-mid-

atlantic-region#section-1˃

Arthington, Angela H., Stuart E. Bunn, N. LeRoy Poff, Robert J. Naiman "The challenge of providing environmental flow rules to sustain river

ecosystems." Ecological Applications 16.4 (2006): 1311-1318.

Ashton, M.J. Ecological responses to flow alteration: A literature review within the context of the Maryland Hydroecological Integrity

Assessment. N.p.: Jan 2013. PDF file.

Bradford, Michael J., and John S. Heinonen. "Low flows, instream flow needs and fish ecology in small streams." Canadian water resources

Journal 33.2 (2008): 165-180.

Carlisle, Daren M., David M. Wolock, and Michael R. Meador. "Alteration of streamflow magnitudes and potential ecological consequences: a

multiregional assessment." Frontiers in Ecology and the Environment 9.5 (2010): 264-270.

Dewson, Zoë S., Alexander BW James, and Russell G. Death. "A review of the consequences of decreased flow for instream habitat and

macroinvertebrates."Journal of the North American Benthological Society 26.3 (2007): 401-415.

Entrekin, Sally, Michelle Evans-White, Brent Johnson, and Elisabeth Hagenbuch. "Rapid expansion of natural gas development poses a threat to

surface waters." Frontiers in Ecology and the Environment 9.9 (2011): 503-511.

˂http://www.esajournals.org/doi/abs/10.1890/110053˃


Falke, Jeffrey A., Kurt D. Fausch, Robin Magelky, Angela Aldred, Deanna S. Durnford, Linda K. Riley and Ramchand Oad. "The role of

groundwater pumping and drought in shaping ecological futures for stream fishes in a dryland river basin of the western Great

Plains, USA." Ecohydrology 4.5 (2011): 682-697.

Gido, Keith B., Walter K. Dodds, and Mark E. Eberle. "Retrospective analysis of fish community change during a half-century of landuse and

streamflow changes." Journal of the North American Benthological Society 29.3 (2010): 970-987.

Hakala, James P., and Kyle J. Hartman. "Drought effect on stream morphology and brook trout (Salvelinus fontinalis) populations in forested

headwater streams." Hydrobiologia 515.1-3 (2004): 203-213.

Heft, Alan A., Ed. Maryland Brook Trout Fisheries Management Plan. nN.p.:2006. PDF file.

Kennen, Jonathan G., Melissa L. Riskin, and Emmanuel G. Charles. "Effects of streamflow reductions on aquatic macroinvertebrates: linking

groundwater withdrawals and assemblage response in southern New Jersey streams, USA."Hydrological Sciences Journal ahead-of-

print (2014): 1-17.

Lytle, David A., and N. LeRoy Poff. "Adaptation to natural flow regimes." Trends in Ecology & Evolution 19.2 (2004): 94-100.

http://extension.psu.edu/natural-resources/water/marcellus-shale/regulations/waters-journey-through-the-shale-gas-drilling-and-production-processes-in-the-mid-atlantic-region#section-1



13



<http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf ˃

National Ground Water Association. Hydraulic Fracturing: Meeting the Nation’s Energy Needs While Protecting Groundwater Resources, 2014.

PDF file. ˂http://www.ngwa.org/Documents/PositionPapers/Hydraulic%20Fracturing%20Meeting%20Energy%20Needs.pdf ˃



Reservoirs. Albany, NY: N.p., 2011. ˂http://www.dec.ny.gov/energy/75370.html˃.

Nicot, Jean-Philippe, and Bridget R. Scanlon. "Water use for shale-gas production in Texas, US." Environmental science & technology 46.6

(2012): 3580-3586.

Poff, N. LeRoy, and Julie KH Zimmerman. "Ecological responses to altered flow regimes: a literature review to inform the science and

management of environmental flows." Freshwater Biology 55.1 (2010): 194-205.

Ricardo-AEA Ltd. “Shale Gas Risk Assessment for Maryland).” N.p.:11 February 2014. PDF file.˂ http://chesapeakeclimate.org/wp/wp-

content/uploads/2014/02/Shale-gas-risk-assessment-for-Maryland_Feb2014.pdf˃

U.S. Geological Survey. “USGS Water Data for the Nation.” Web. 11 August 2014. <http://waterdata.usgs.gov/nwis/>.

Water Appropriation for Use. Division of State Documents. COMAR 26.17.06. (May 1, 1972).

Weltman-Fahs, Maya, and Jason M. Taylor. "Hydraulic fracturing and brook trout habitat in the Marcellus Shale region: potential impacts and

research needs." Fisheries 38.1 (2013): 4-15.

Wills, Todd C., Edward A. Baker, Andrew J. Nuhfer and Troy G. Zorn. "Response of the benthic macroinvertebrate community in a northern

Michigan stream to reduced summer streamflows." River Research and Applications 22.7 (2006): 819-836.


http://www.ngwa.org/Documents/PositionPapers/Hydraulic%20Fracturing%20Meeting%20Energy%20Needs.pdf


http://chesapeakeclimate.org/wp/wp-content/uploads/2014/02/Shale-gas-risk-assessment-for-Maryland_Feb2014.pdf


http://waterdata.usgs.gov/nwis/

i

Appendix H

Wells and Formations

Introduction ............................................................................................................................................................ 1

Impact of Groundwater Contamination ................................................................................................................. 2

Risk Mitigation (Current Regulations & Proposed BMPs) ...................................................................................... 3

Existing Regulations ........................................................................................................................................... 3

Best Practices ..................................................................................................................................................... 3

Risk Assessments .................................................................................................................................................... 5

Saline intrusion during drilling ........................................................................................................................... 5

Saline intrusion due to casing or cement failure ............................................................................................... 6

Methane intrusion from casing and/or cementing failure ................................................................................ 7

Contaminant migration through faults and old wells ........................................................................................ 9

Seismic vibrations from underground injection .............................................................................................. 10

Impact to groundwater from deep well injection of wastewater ................................................................... 11

References ............................................................................................................................................................ 15

Figure 1: Pathways of Groundwater Contamination 1

Figure 2: Potential Gas Migration Paths along a Well 8

Risk Assessment Table 13

1

Introduction

This appendix evaluates risks associated with contamination of groundwater during the drilling of a well,

due to casing and cementing failures, interactions with other formations (e.g. natural voids, faults) and

historic gas wells, and deep well waste injection. Specifically, the following seven risks were identified by

the Advisory Commission and were grouped as being associated with wells and formations. An

additional risk was added in order to evaluate a contamination pathway for methane (#6 below) as well

as fluids (#5 below).

1. Impact to groundwater from saline intrusion during drilling of vertical and lateral wellbore

2. Impact to groundwater from methane due to drilling through coalbed or other methane containing formations

3. Impact to groundwater from saline intrusion due to casing and cementing failure

4. Impact to groundwater from methane due to casing and cement failure

5. Impact to groundwater from fracturing fluids and mobilized substances via migration through faults and old wells

6. Impact to groundwater from methane due to migration through faults and old wells

7. Impact to community from seismic vibrations caused by deep underground injection

8. Impact to groundwater from deep well injection of flowback and produced water

Figure 1: Pathways of Groundwater Contamination

(1) overuse of water that could lead to depletion and water quality degradation particularly in water-scarce areas;

(2) surface water and shallow groundwater contamination from spills and leaks of wastewater storage and open

pits near drilling; (3) disposal of inadequately treated wastewater to local streams and accumulation of

contaminant residues in disposal sites; (4) leaks of storage ponds that are used for deep-well injection; (5) shallow

aquifer contamination by stray gas that originated from the target shale gas formation through leaking well casing.

The stray gas contamination can potentially be followed by salt and chemical contamination from hydraulic

2

fracturing fluids and/or formational waters; (6) shallow aquifer contamination by stray gas through leaking of

conventional oil and gas wells casing; (7) shallow aquifer contamination by stray gas that originated from

intermediate geological formations through annulus leaking of either shale gas or conventional oil and gas wells;

(8) shallow aquifer contamination through abandoned oil and gas wells; (9) flow of gas and saline water directly

from deep formation waters to shallow aquifers; and (10) shallow aquifer contamination through leaking of

injection wells. (Vengosh 2014)

Impact of Groundwater Contamination

As described above, this appendix evaluates eight individual contamination pathway combinations.

These can be simplified into two broad categories – contamination of groundwater from methane or

contamination from other liquids (saline, fracturing fluids, and other formation liquids). Contamination

of groundwater from any of these substances would have a negative impact on human health and

aquatic life. The main BMPs to prevent contamination of groundwater are effective cementing and

casing and monitoring for leaks.

Based on the literature reviewed, evidence has shown contamination from methane to be a likely

occurrence. Methane is buoyant and moves upwards, whereas liquids generally move in response to

pressure gradients. The strongest evidence of methane contamination of groundwater has been

presented by Osborn et al. (2013), showing statistically higher levels of methane within 1 km of active

drilling areas. The pathway of contamination (e.g. cement/casing failure, migration through faults) is not

identified.

Methane is a colorless, odorless gas that does not affect the taste or appearance of drinking water,

except that it can cause the water to appear cloudy or produce effervescent gas bubbles. There is no

evidence that ingestion of methane in drinking water affects human health. (NIOSH). Methane is

extremely flammable and can form an explosive mixture with air at concentrations between 5% (lower

explosive limit) and 15% (upper explosive limit). The US Department of the Interior, Office of Surface

Mining, suggests that when the level of methane gas in the water is less than 10 mg/L it is safe, but

monitoring is required at 10 to 28 mg/L, and immediate action is needed above 28 mg/L. (Eltschlager,

2001). Methane in its gas form is a simple asphyxiant, which in high concentrations may displace the

oxygen supply needed for breathing, especially in confined spaces. Decreased oxygen can cause

suffocation and loss of consciousness. It can also cause headache, dizziness, weakness, nausea,

vomiting, and loss of coordination. Skin contact with liquid methane (which is very cold) can cause

frostbite (NIH, 2014).

The impact of contamination of groundwater from the various liquids is somewhat harder to evaluate

because of the number of chemicals present in drilling fluids and fracturing fluids, as well as deep

underground formations of saline water and naturally occurring radioactive material (NORM). The

precise composition of these liquids is often unknown and therefore there is insufficient data to

3

determine to what extent it will impact human health or aquatic life. The following chemicals that are

human health hazards have been used in the fracturing process: methanol, ethylene glycol, diesel fuel,

napthalene, etc. (Waxman, 2011). Saline contamination would render groundwater unusable for

drinking water and could also impact aquatic life that need freshwater. Overall, more research is needed

to evaluate the impact of these liquids on groundwater.

Risk Mitigation (Current Regulations & Proposed BMPs)

Many of the risks associated with contamination to groundwater can, in some part, be reduced by

current State regulations, as well as by the recommendations found in Marcellus Shale Safe Drilling

Initiative Study, Part II: Interim Final Best Practices (MDE & DNR, 2014). The following is a summary of

regulations and BMPs that can be expected to help prevent or mitigate groundwater contamination.

This list will be used throughout the appendix to refer back to the detailed information given here.

Existing Regulations

The Code of Maryland Regulations (COMAR) Chapter 26.19.01 establishes regulations regarding Oil and

Gas Resources in the State. The following requirements regarding setbacks, isolation of fresh water, and

plugging of abandoned wells will help mitigate contamination of groundwater. If the recommended best

practices are more stringent than the existing regulations, the existing regulations are not mentioned.

COMAR 26.19.01.10

o Determination of the depth of fresh water zones o Run and permanently cement surface casing in the hole to a depth which is at least 100

feet below the deepest known strata bearing fresh water, or the deepest known workable coal, whichever is deeper

o If other strings of casing, in addition to surface casing, are run in the hole, they shall be cemented with sufficient cement circulated in the annular space to provide an effective seal above any producing zone;

o Within 30 days after the drilling, stimulating, and testing of a well are completed, a completion report of the well shall be submitted to the Department.

COMAR 26.19.01.12

o Upon the abandonment or ending of operation of any dry hole, gas or oil well, storage well, pressure maintenance well, or stratigraphic well, the permittee shall plug the hole.

Best Practices

In addition to the regulations, Marcellus Shale Safe Drilling Initiative Study, Part II: Best Practices

includes many practices that will help mitigate groundwater contamination. These include:

Preparation of a Comprehensive Gas Development Plan (CGDP) that, to the maximum extent practicable, avoids impacts to natural, social, cultural, recreational and other resources, minimizes unavoidable impacts, and mitigates remaining impacts

The CGDP must include a geological investigation by the applicant of the area covered by the CGDP. At a minimum, the geological survey will include location of all gas wells (abandoned and existing), current

4

water supply wells and springs, fracture-trace mapping, orientation on the location of all joints and fractures and other additional geologic information as required by the State. The applicant will be required to submit the survey data to the State; however, if the applicant asserts that the geological information is confidential business information, the State will not release the information to the public for a period of three years

Setbacks from edge of disturbance for well pad o 1,000 feet from the boundary of the property on which the well will be drilled (a waiver can be

granted if this is infeasible) o 450 feet from aquatic habitat o 600 feet from special conservation areas o 750 ft setback from downdip side of limestone outcrops to borehole o 1,000 feet from a school, church, or other occupied building (Unless written permission of the

owners is submitted with the application and approved by the Department) o 1,320 ft setback from historic gas wells to borehole, including laterals o 2,000 foot setback from a private drinking water well o 1,000 foot setback from the perimeter of a wellhead protection area or source water assessment



Site evaluation, pilot hole investigation and geologic investigation to develop site specific drilling, casing and cementing techniques in the event well drilling will encounter coal mines.



State agencies will develop standard protocols for baseline and environmental assessment monitoring, recordkeeping and reporting. In addition, the State agencies will develop standards for monitoring during operations at the site, including drilling, hydraulic fracturing, and production

The monitoring, recordkeeping and reporting requirements will assist with identification of impacts from hazardous material releases so that remediation can be appropriate.

Pre-development environmental assessment of site to identify all on-site drilling hazards such as underground mine workings, orphaned gas or oil wells, caves, caverns, Karst features, etc.

Diesel fuel shall not be used in hydraulic fracturing fluids

The permittee will be required to provide a complete list (Complete List) of chemical names, CAS numbers, and concentrations of every chemical constituent of every commercial chemical product brought to the site. If a claim is made that the composition of a product is a trade secret, the permittee must provide an alternative list (Alternative List), in any order, of the chemical constituents, including CAS numbers, without linking the constituent to a specific product. If no claim of trade secret is made, the Complete List will be considered public information; if a claim is made, the Alternative List will be considered public information.

Following well completion, the operator shall provide MDE with a list of all chemicals used in fracturing, the weight of each used, and the concentration of the chemical in the fracturing fluid. If a claim is made that the weight of each chemical used or the concentration of each chemical in the fracturing fluid is a trade secret, the operator may attest to that fact and provide a second list that omits the weight and concentration to the extent necessary to protect the trade secret. If no claim of trade secret is made, the full list shall be public information; if a claim of trade secret is made, the list without the trade secret weight and concentration shall be public information.

The applicant for an individual well permit must submit a plan for construction and operation that meets or exceeds the standards and/or individual planning requirements for engineering, design and environmental controls. In preparing the plan, the applicant shall consider all relevant API Standards and Guidance Documents, including normative references, and, if the plan fails to follow a minimum requirement of a relevant API standard, the plan must explain why and demonstrate that the plan is at least as protective as the minimum requirement. Elements of the plan include:

5

o Evaluation of potential flow zones. Identification and evaluation of shallow and deep hazards o Monitoring and maintaining wellbore stability o Addressing lost circulation o Casing o Cementing o Wellbore hydraulics o Integrity and pressure testing

Performance of well logging and submission of results to the State o Open hole logging o Cased hole logging using segmented radial cement bond logging, supplemented by other

methods including omnidirectional cement bond logging and observations and measurements during cementing.

Requirements for casing and cement o Steel alloy casing that meets standards for construction and pressure o Coupling threads that meet API standards o Use of centralizers o The cement shall be allowed to set at static balance or under pressure for a minimum of 12 hours

and must have reached a compressive strength of at least 500 psi before drilling the plug, or initiating any integrity testing

o Reconditioned casing may be permanently set in a well only after it has passed a hydrostatic pressure test with an applied pressure at least 1.2 times the maximum internal pressure to which the casing may be subjected, based upon known or anticipated subsurface pressure, or pressure that may be applied during stimulation, whichever is greater, and assuming no external pressure. The casing shall be marked to verify the test status.

o All hydrostatic pressure tests shall be conducted pursuant to API “5 CT Specification for Casing and Tubing” or other method(s) approved by the Department. The owner shall provide a copy of the test results to MDE before the casing is installed in the well

o Surface casing shall be run and permanently cemented from the surface to a depth at least 100 feet below the deepest known stratum bearing fresh water, or the deepest known workable coal, whichever is deeper. Intermediate casing, if used, must isolate all fluid bearing zones through which it passes. Production casing must be cemented along the horizontal portion of the well bore and to at least 500 feet above the highest formation where hydraulic fracturing will be performed, or 500 feet above the uppermost fluid bearing formation not already isolated by surface casing or intermediate casing, whichever is shallower.

o If there is evidence of inadequate casing integrity or cement integrity, the Department must be notified and remedial action proposed.

Risk Assessments

Saline intrusion during drilling

The section evaluates the impact to groundwater from saline intrusion during drilling of vertical and

lateral wellbore or from methane due to drilling through coalbed or other methane containing

formations

Literature Review

No literature sources were found specifically related to contamination of groundwater by methane or

saline water during the drilling of the wellbore. Most literature sources are concerned with fluid and gas

migration to groundwater through cement/casing failure or other subsurface formations, which will be

evaluated later in this appendix. Contamination during drilling is more likely due to drilling muds and

cuttings, which will be evaluated in another section of this report.

6

Regarding saline contamination, in order for saline intrusion to occur during the drilling of the wellbore,

both the fresh water and saline formations would need to be exposed simultaneously. As noted above,

the surface casing must be installed and cemented to at least 100 feet below the deepest known strata

bearing fresh water, or the deepest known workable coal, whichever is deeper, and the cement must be

allowed to set before drilling the plug, which must be done before drilling deeper. The deepest stata

bearing fresh water will ordinarily be established during drilling of the pilot hole. Also, as depicted in

Figure 1 above, there is often great distance between the groundwater and saline formations, which

would reduce the chance that they are exposed simultaneously.

Risk Analysis

Regarding methane contamination, the first priority should be to isolate fresh water strata as efficiently

as possible, and secondly, to isolate other fluid-bearing zones. Intermediate casing, if used, must isolate

all fluid bearing (liquid or gas) zones through which it passes. Production casing must be cemented along

the horizontal portion of the well bore and to at least 500 feet above the highest formation where

hydraulic fracturing will be performed, or 500 feet above the uppermost fluid bearing formation not

already isolated by surface casing or intermediate casing, whichever is shallower. In this way, casing and

cement will isolate all fluid-bearing (gas and liquid) formations through which the borehole passes

before reaching the target formation.

Probability:

The probability of saline or methane contamination during drilling is rated as low based on the absence

of reported cases, the best practices that require isolation of all fluid-bearing strata, and the relatively

large separation between fresh water and salt water formations.

Consequence:

Impacts to groundwater could cause considerable adverse impact on people or the environment in the

vicinity and is therefore rated as a moderate consequence.

Saline intrusion due to casing or cement failure

This section evaluates the impact to groundwater from saline intrusion due to casing and/or cementing

failure

Literature Review

Few literature sources were found related to groundwater contamination by saline due to

casing/cement failure. Based on literature review, it is more likely that gas will be released in the event

of casing/cement failure. However, it is notable that casing/cement failure is one of the most likely

causes of environmental contamination in the hydraulic fracturing process.

7

Several literature sources state that no evidence of contamination of drinking water from deep saline

brines was found. (Osborn et al., 2011 & Jackson, 2013) In a recent report investigating the mechanisms

by which human activity could cause methane gas contamination to occur in drinking water wells, the

authors noted that samples with significantly higher levels of thermogenic gas did not correlate with

chloride levels, indicating that the thermogenic hydrocarbon gas had separated from the brine and

migrated in the gas phase. For other samples where gas and brine levels did correlate, they concluded

that the presence of gas and Cl- was indicative of natural in situ presence or tectonically driven migration

over geological time of gas-rich brine from an underlying source formation or gas-bearing formation of

intermediate depth. (Darrah et al., 2014) This would indicate that saline intrusion was not caused by

casing/cementing failure or any other step in the hydraulic fracturing process. Additionally, due to the

density of saline brine, it is not likely to move upward through casing/cementing failures without

significant induced pressure.

Risk Analysis

The best practices for casing and cement will reduce the risk of casing and cement failures.

Probability:

The probability of saline or methane contamination during drilling is rated as low based on the absence

of reported cases and the best practices for casing and cement.

Consequence:



Methane intrusion from casing and/or cementing failure

Literature Review

It is widely believed that casing/cement failure is one of the most likely causes of environmental

contamination in the hydraulic fracturing process. (Darrah et al., 2014; Ingraffea et al., 2014, Vengosh,

2014; Rozell & Reaven, 2012). One source notes that gas migration through faulty casing is a “common

occurrence” in the gas industry (Muehlenbachs, 2011).

There are several pathways for gas migration in a faulty well, as shown in Figure 2 below (Ingraffea,

2012). Ingraffea cites an approximate 6-7% failure rate in Pennsylvania wells (Ingraffea, 2012), while

Vengosh presents findings from various sources estimating from 3 – 50% failure rates (Vengosh, 2014). It

should be noted that there can be a wide range of issues which could constitute “failure” and that not

all lead to contamination.

8

Figure 2: Potential Gas Migration Paths along a Well

Zoback assesses the risk of groundwater contamination from casing or cement failure as great. A 2007

example is given of groundwater contamination in Ohio from a well that was almost 4,000 feet deep in

tight sands, via cement failure.

In a report to the US Department of Energy, the Secretary of the Energy Advisory Board (SEAB) states

that contamination from methane is widely believed to be due to poor well completion. The

recommend multiple engineered barriers to prevent groundwater contamination from methane and

that properly cemented and cased wells do not allow contamination (SEAB, 2011).

A study in Pennsylvania documented elevated levels of methane in groundwater wells within 1 km of

natural gas wells compared to groundwater wells farther away and the authors identified several

possible mechanisms. (Jackson, 2013) A subsequent investigation tested the likelihood of seven

different scenarios that, alone or together, could account for the elevated methane levels in shallow

aquifers. The authors concluded that of the eight clusters of groundwater wells that showed fugitive gas

contamination, four were consistent with the release of intermediate-depth hydrocarbon gas along the

well annulus, probably as a result of poor cementation. Three of the remaining four were consistent

with migration of deep shale gas, “presumably” through improper, faulty or failing production casing.

The eighth cluster was located near a natural gas well that had documented an underground well failure

(a casing well packer failure at depth). (Darrah, 2014) In contrast, an investigation in the Fayetteville

shale in north-central Arkansas found no direct evidence for stray gas contamination in wells located

near shale gas sites. (Warner, 2013) One of the authors wrote that “The authors hypothesized the

potential for stray gas contamination likely depends on both well integrity and local geology, including

9

the extent of local fracture systems that provide flow paths for potential gas migration” (Vengosh,

2014).

Risk Analysis

The best practices for casing and cement reduce the risk of casing and cement failures. Integrity testing

may identify problems that can be remedied. Setbacks from source water protection areas and private

drinking water wells also reduce the likelihood that stray methane will reach wells. The geological survey

of the area covered by the Comprehensive Gas Development Plan will provide information about the

locations of existing joints and fractures.

Probability:

Failures of casing and cement are common and, although the best practices should greatly reduce them,

they probably will not be eliminated. The probability of groundwater contamination via casing/cement

failure is being evaluated for two scenarios, based on MDE’s Best Practices recommendations. The first

scenario is if a private drinking water well is within 2,000 feet of a drinking water source and the

probability for this is moderate. The second scenario is if a well is further than 1 km (3,280ft) from a

drinking water source, and the probability for this is low.

Consequence:



Contaminant migration through faults and old wells

This section evaluates the impact to groundwater from fracturing fluid, flowback and methane via

migration through faults and old wells.

Literature Review

Most literature sources indicate that groundwater contamination via migration through faults or old

wells would be a rare and site specific occurrence.

Zoback (2014) states that the risk of migration from methane or fluids from Marcellus Shale, which is

4,000 to 8500 feet below the surface, to groundwater which is approximately 850 feet below the surface

is very low. He does state that there are shallower shales, such as Antrim or New Albany, which

migration could be significant.

Rozell and Reaven (2012) used probability bounds analysis (PBA) to evaluate risk of five pathways for

water contamination. The lack of consensus on the likelihood that hydraulic fracturing fluids would

migrate through fractures resulted in a probability range of 1 in 10 to 1 in a million.

Vengosh (2014) reports that methane and fluid migration to groundwater is highly debated. An

investigation of mechanisms for stray gas migration found no unequivocal evidence that stray gas

contamination of shallow groundwater was caused by direct migration of gases upward through

intervening strata following drilling or hydraulic fracturing; the cluster that was consistent with

10

migration of gas from depth through water-saturated strata in the crust to the shallow aquifer was more

likely caused by the documented underground well failure (Darrah 2014).

The SEAB reports that regulators and geophysical experts agree that the likelihood of properly injected

fracturing liquid or naturally occurring contaminants reaching underground sources of drinking water

through fractures is remote where there is a large depth separation between drinking water sources and

the producing zone (SEAB, 2011).

Vidic (2013) indicates that fluid migration through natural faults is possible when brines are present at

relatively shallow depths, such as in much of the northeastern and southwestern United States and

Michigan.

Risk Analysis

The best practices for casing and cement reduce the risk of casing and cement failures. Integrity testing

may identify problems that can be remedied. Setbacks from source water protection areas and private

drinking water wells also reduce the likelihood that stray methane will reach wells. The geological survey

of the area covered by the Comprehensive Gas Development Plan will provide information about the

locations of existing joints and fractures as well as old wells.

Probability:

Based on the literature review and BMPs available, the risk is classified as low.

Consequence:


vicinity and is as a moderate consequence for people and a serious consequence for the environment.

Aquatic organisms are highly sensitive to dissolved toxins and the uncertainty regarding the specific

chemical composition of fluids and the specific sensitivity of the exposed organisms warrents are greater

consequence. Cave systems and their unique biological communities are also particularly sensitive to

groundwater toxins.

Seismic vibrations from underground injection

This section evaluates the impact to communities from seismic vibrations caused by deep well injection

of wastewaters.

Literature Review

While many industries dispose of waste to deep wells, the high volume of wastes associated with

hydraulic fracturing that will need to be disposed of to deep disposal wells is a concern. There is

significant consensus that waste disposal to deep wells has caused an increase in seismic activities.

In early 2014, USGS published an article on their website, Man-made Earthquakes Update. It reported

that the number of earthquakes has increased recently, especially in the central and eastern United

11

States. In some locations, they were able to directly connect the increase in seismicity with the injection

of wastewater in deep disposal wells. Deep injection disposal in often used by the oil and gas industry

into wells specifically designed for such purpose. (USGS 2014)

Ellsworth (2013) reports a growing realization that the principal seismic hazard from injection-induced

earthquakes comes from those associated with disposal of wastewater into deep strata.

King (2012) cites established connections between earthquakes and deep well disposal of some

produced water from the oil and gas industry, as well as injection of other fluids such as military wastes

and wastes from geothermal energy production.

Zoback (2010) details a number of the small-to-moderate earthquakes that occurred in the U.S. interior

in 2011 appear to be associated with the disposal of wastewaters, in part from natural gas production.

These include locations in Arkansas, Colorado/New Mexico, and Ohio.

Risk Analysis

With regard to disposal in Class II injection wells, the UMCES-AL report noted that locations in Maryland

suitable for siting injection wells may be very limited. MDE and DNR agree that it is not likely that Class II

wells will be located in Maryland and therefore defers any consideration of the matter.

In response to the increase in the frequency of seismic events associated with underground injection,

Governor Mary Fallin established a working group, the Coordinating Council on Seismic Activity, to

investigate the issues. (Oklahoma, 2014) In Texas, the regulatory agency has proposed regulations that

would require applicants for injection well permits to provide information regarding historic seismic

events and monitor injection pressure and injection rates as required by the commission. (Railroad

Commission of Texas, 2014)

Probability

Based on the literature review, risk of seismic activity due to deep underground injection is moderate

because it occurs occasionally or could potentially occur under foreseeable circumstances if

management or regulatory controls fall below best practice standards. However, because it is not likely

that Class II wells will be located in Maryland, this risk is assumed to have a low probability.

Consequence

The consequence of an earthquake induced by deep well injection would be serious because it would

have a major adverse impact on people or the environment.

Impact to groundwater from deep well injection of wastewater

This section evaluates the impact to groundwater of deep well injection of wastewaters.

Literature Review

The consensus from literature sources indicates that it is possible that fluids disposed of via deep well

injection could contaminate groundwater, but that it is rare.

12

McLin (1986) reports that no systematic survey has been completed to determine the extent of

groundwater contamination from deep well injection.

Vidic (2013)states that between 1982 and 1984, Texas reported at most approximately 100 cases of

confirmed contamination of groundwater from oilfield injection wells, despite more than 50,000

injection wells associated with the oil and gas industry.

An American Petroleum Institute reports estimated the risk of contaminating groundwater from a Class

II injection well at 2 in 100,000 well-years to 2 in 100,000,000 well-years (Rozell & Reaven, 2012).

Risk Analysis

With regard to disposal in Class II injection wells, the UMCES-AL report noted that locations in Maryland

suitable for siting injection wells may be very limited. MDE and DNR agree that it is not likely that Class II

wells will be located in Maryland and therefore defers any consideration of the matter.

Probability

Based on the literature review, contamination of groundwater due to deep underground injection rarely

happens and therefore the probability is low. However, because it is not likely that Class II wells will be

located in Maryland, this risk is assumed to have a low probability in Maryland.

Consequence



13

Risk Assessment Table

Risk Environmental Impact Probability Consequence Risk Ranking

Impact to groundwater from

saline intrusion during drilling of

vertical and lateral wellbore

Human and Ecological Low Moderate Low


methane due to drilling through

coalbed or other methane

containing formations



saline intrusion due to casing and

cementing failure



methane due to casing and

cement failure if well is within

2,000 feet

Human Moderate Moderate Moderate


methane due to casing and

cement failure if well is greater

than 3280 feet away



fracturing fluids and mobilized

substances via migration through

faults and old wells


14


fracturing fluids and mobilized

substances via migration through

faults and old wells

Ecological Low Serious Moderate


methane due to migration

through faults and old wells


Impact to community from

seismic vibrations caused by deep

underground injection

Community Low – MD Serious Moderate

Impact to community from

seismic vibrations caused by deep

underground injection

Community Moderate – States with

Class II wells

Serious High


deep well injection of flowback

and produced water

Human Low – MD Moderate Low


deep well injection of flowback

and produced water

Human Moderate – States with

Class II wells

Moderate Moderate

15

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Rishmani “From Mud to Cement – Building Gas Wells.” Oilfield Review 15.3 (2003): 62 – 76. Web.

˂http://www.fraw.org.uk/files/extreme/brufatto_2003.pdf.˃

Ellsworth, W. L. “Injection-induced earthquakes.” Science 341.6142 (2013) : 142 – 149. Web. ˂http://fracklist.org/wp-

content/uploads/2014/06/140602073601_Ellsworth.Injection-Induced_Earthquakes.final_.pdf˃

Darrah, Thomas H., Avner Vengosh, Robert B. Jackson, Nathaniel R. Warner, and Robert J. Poreda. "Noble gases identify the mechanisms of

fugitive gas contamination in drinking-water wells overlying the Marcellus and Barnett Shales." Proceedings of the National Academy

of Sciences (2014): 201322107. ˂http://www.pnas.org/content/early/2014/09/12/1322107111.full.pdf+html˃

Eltschlager, Kenneth K., Jay W.Hawkins, William C. Ehler, and Fred Baldassare, U.S. Dept. of the Interior, Office of Surface Mining Reclamation

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Ingraffea, Anthony R. "Fluid migration mechanisms due to faulty well design and/or construction: An overview and recent experiences in the

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Ingraffea, Anthony R., et al. "Assessment and risk analysis of casing and cement impairment in oil and gas wells in Pennsylvania, 2000–

2012."Proceedings of the National Academy of Sciences 111.30 (2014): 10955-10960

˂http://www.pnas.org/content/early/2014/06/25/1323422111.full.pdf+html˃

Jackson, Robert B., Avner Vengosa, Thomas H. Darrah, Nathaniel R. Warner, Adrian Down, Robert J. Poreda, Stephen G. Osborn, Kaiguang Zhao,

and Jonathan D. Karr . "Increased stray gas abundance in a subset of drinking water wells near Marcellus shale gas

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http://arblast.osmre.gov/downloads/Mine%20Gases%20and%20Dust/FINAL-Methane.pdf


http://www.psehealthyenergy.org/data/PSE__Cement_Failure_Causes_and_Rate_Analaysis_Jan_2013_Ingraffea1.pdf



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i

Appendix I

Risk Assessment: Waste Disposal

Introduction ............................................................................................................................................................ 1

Regulatory Overview .............................................................................................................................................. 1

Types of Waste ....................................................................................................................................................... 3

Liquids: Produced Water ................................................................................................................................... 3

Solids: Drill Cuttings, Drilling Muds, Sludges and Brine Scales .......................................................................... 4

Waste Treatment, Reuse and Disposal Options ..................................................................................................... 5

Beneficial Uses ................................................................................................................................................... 5

Assessment of Risks ................................................................................................................................................ 7

Liquids - Road Application (formation water only) ............................................................................................ 7

Agricultural Soil Amendments ........................................................................................................................... 8

Solids - Road construction (cuttings only) ......................................................................................................... 9

On-site Disposal ............................................................................................................................................... 11

Disposal in a Landfill ........................................................................................................................................ 11

Land farming .................................................................................................................................................... 12

Conclusion ............................................................................................................................................................ 13

References ............................................................................................................................................................ 15

Summary Table of Probability, Consequence and Risk Ranking 14

1

Introduction

The assessment presented in this appendix addresses the risks associated with the disposal and

beneficial use of liquid or solid wastes generated during unconventional gas well development (UGWD).

Liquid wastes include flowback of fracturing fluid, produced water, and spent treatment fluids. Solid

wastes include: drill cuttings, drilling muds, sludges and exhausted filter media, and brine scales. The

term “disposal” means that waste material is placed permanently and is not expected to be relocated or

disturbed. The term “beneficial use” means that the waste product is reprocessed into additional

materials or new products. The reuse of hydraulic fracturing fluids during the drilling and well

stimulation, however, is covered in Appendix 3-Drilling Fluids and Cuttings. This assessment attempts to

account for immediate as well as cumulative or long term risks. Summary risks are assessed on a

method-material basis. For example the risks associated with the disposal of cuttings in solid waste

landfills will consider the risks to ground water, surface water, and public health associated the disposal

of the cuttings.

This assessment will provide an overview of related regulatory and/or State policies regarding the

disposal of or reuse of UGWD wastes. That is followed by general descriptions of each type of waste

generated during the UGWD process. The last portion of this assessment discusses the risks, probability

and consequences, of various final waste disposal and beneficial use methods.

This appendix does not address the risks of transporting wastes, which is covered in another appendix.

This appendix does not cover the actual capacity of the State to accommodate wastes.

This appendix does not evaluate disposal methods currently unavailable in the State of Maryland. Those

methods include: direct discharge pursuant to a permit, discharge to publicly owned treatment works

(POTW), and disposal in a Class II injection well.

Regulatory Overview

Federal regulations mandate that “there shall be no discharge of waste water pollutants into navigable

waters from any source associated with production, field exploration, drilling, well completion, or well

treatment (i.e., produced water, drilling muds, drill cuttings, and produced sand)” (40 CFR 435.32). Thus,

the direct discharge of flowback or other brine is already prohibited.

2

EPA has committed to develop standards to ensure that wastewaters from gas extraction receive proper

treatment and can be properly handled by POTWs. EPA plans to propose a rule for shale gas wastewater

in 2014. Until these regulations are in place, MDE has requested that POTWs not accept these

wastewaters without prior consultation with MDE. MDE does not intend to authorize any POTW that

discharges to fresh water to accept these wastewaters.

There are currently no Class II injection wells in Maryland, and the geology here is generally unfavorable

for locating such wells. Class II injection wells in other states may accept wastes from gas production in

Maryland. EPA and states that have experienced an increase in seismic events associated with Class II

injection wells have recognized the risk and are taking steps to address it.

In response to the increase in the frequency of seismic events associated with underground injection,

Governor Mary Fallin established a working group, the Coordinating Council on Seismic Activity, to

investigate the issues. (Oklahoma, 2014) In Texas, the regulatory agency has proposed regulations that

would require applicants for injection well permits to provide information regarding historic seismic

events and monitor injection pressure and injection rates as required by the commission. (Railroad

Commission of Texas, 2014)

Solid wastes generated during the exploration, development, and production of crude oil, natural gas,

and geothermal energy are exempt from federal hazardous waste regulations under Subtitle C of the

Resource Conservation and Recovery Act (RCRA)( 40 CFR 261.4(b)(5)). The federal rule was adopted by

the Department; COMAR 26.13.02.04-1(A)(5) states that “Drilling fluids, produced waters, and other

wastes associated with the exploration, development, or production of crude oil, natural gas, or

geothermal energy;” are considered nonhazardous wastes. EPA has clarified the scope of the

exemption: “All wastes located at E&P [exploration and production] sites are not necessarily exempt. To

be considered an exempt waste, the waste must have been generated from a material or process

uniquely associated with the exploration, development, and production of crude oil and natural gas. For

example, a solvent used to clean surface equipment or machinery is not exempt because it is not

uniquely associated with exploration, development, or production operations. Conversely, if the same

solvent were used in a well, it would be exempt because it was generated through a procedure that is

uniquely associated with production operations.” (EPA, 2002, p. 18). Many of the wastes generated at

gas well pads in large quantities are exempt, including produced water, drilling fluids, drill cuttings, and

well completion, treatment, and stimulation fluids. Id. at 10. They are nevertheless solid wastes, and

must be managed and disposed of in accordance with laws governing nonhazardous solid wastes. Solid

waste may be disposed of, recycled, or considered for beneficial reuse.

3

The non-exempt hazardous wastes generated by oil and gas exploration and production are similar to

hazardous wastes generated by other industrial sectors and pose no unique risks. They will not be

further considered in this risk assessment.

Wastewater may be suitable for disposal by spray irrigation or other land application. This requires a

State Ground Water Discharge Permit. Such permits contain the limitations and requirements deemed

necessary to protect public health and protect ground water quality.

Nonhazardous liquid wastes may only be disposed of at a solid waste acceptance facility that has been

specifically authorized by the Department to handle those wastes. Liquid wastes may be mixed with

sorbent or solidified to qualify. The presence of free liquids shall be determined by application of the

free liquid test as specified in 47 FR 8311 (1982), which is commonly called the pint filter test.

Solid nonhazardous wastes can be disposed of in a county/municipal landfill. Solid waste acceptance

(SWA) facilities must possess a Refuse Disposal (RD) Permit for the installation, alteration, or extension

of a SWA facility. The RD Permit regulates the design, construction, operation, and monitoring of such

facilities to minimize the impact on public health and the environment). The only SWA facilities

regulated by a RD Permit included in this risk assessment are municipal landfills, rubble [construction

and demolition (C&D) debris] landfills and non-hazardous industrial waste landfills.

Types of Waste

Liquids: Produced Water

In this risk assessment, produced water refers to all water that returns to the surface through the well

borehole. It is made of returning hydraulic fracturing fluid and natural formation water. Flowback is

composed of the fracturing fluids pumped into the well which return up the well to the surface and

produced water, which is water trapped in underground formations that is brought to the surface during

oil and gas exploration and production. The fracturing fluid flowback consists of water and additives;

any new compounds that may have formed due to reactions between additives; and substances

mobilized from within the shale formation due to the fracturing operation. Produced water from the

Marcellus Shale is characterized by its high salinity and total dissolved solids and may contain a variety

of elements such as potassium, calcium, silicon, sodium, magnesium, tin, sulfur, strontium, zinc,

rubidium, arsenic and chromium, some of which exhibit radioactivity. Produced water can also contain

organic compounds, including volatile organic compounds (VOCs). A recent analysis of Marcellus shale

produced water found that the organic molecules were principally saturated hydrocarbons, with

relatively lower levels of aromatic, resin and asphaltene compounds (Maguire-Boyle & Barron, 2014).

4

Solids: Drill Cuttings, Drilling Muds, Sludges and Brine Scales

Drill Cuttings

The majority of the solid wastes generated during UGWD are drill cuttings. Cuttings are generated

during well boring. Cuttings consist of small or fine grained rock chips and fragments that are brought to

the surface as the borehole progresses through the formations. Cuttings return to the surface mixed

with the drilling muds. They are separated from the muds through shaker screens, desanders, desilters,

and centrifuges (NYSDEC, 2011, 5-129). Cuttings from the target formation can have elevated levels of

naturally occurring radioactive materials (NORM) although some reports indicate levels of radioactivity

similar to background values. (NYSDEC, 2010, 5-34). Drill cuttings may be mixed with other materials to

solidify them or stabilize them so that they can be disposed of on-site or at a solid waste facility

(DWMIS).

Drilling Muds

Drilling mud is the mixture that helps maintain borehole stability, push rock fragments to the surface

and also serves to cool and keep the drill head lubricated during the drilling phase of the UGWD process.

The most common freshwater mud constituent is bentonite clay, but it may also contain weighting

agents, clay, polymers, surfactants and other chemicals. MDE and MDNR. 2014). A barium sulfate

weighing agent may be added to bentonite drilling muds. (King, 2012); Bentonite clays are naturally

occurring cationic silicate clays that have cation exchange capacity, often involving Ca+ and Mg+.

Sodium bentonite, the bentonite used in drilling operations, has the ability to absorb great amounts of

water enabling it to seal and lubricate the borehole.

Once the drilling has progressed past the freshwater aquifers other potassium chloride/polymer-based

oil lubricant, or synthetic oil based muds are used to drill the horizontal potion of the well (NYSDEC,

2011 5-32, King 2012). Water based muds are not reused, but the synthetic or oil lubricated muds can

be reused in the drilling process (DWMIS, King, 2012).

Sludges

Sludges and exhausted filter media are generated during the treatment process that allows the fluid and

mud returns to be reused in the drilling process. The constituents of the sludge and filter media vary

widely depending upon the treatment process utilized. Sludges can be generated in a number of ways

5

such as the separation of liquids from solids within the flowback, the addition of coagulants, and the

precipitation of the dissolved solids. Sludges and spent filter media may be dried to a solid cake after

bulking with fly ash or some other additive which makes transport and disposal easier (Hackney &

Weisner, 1996). Sludges must be converted to solids for disposal in a landfill.

Brine Scales

Brine scales are generated during the drilling process as a result of the precipitation of scale forming

metals such as barium, strontium, calcium, and magnesium found in the formation water co-produced

during the drilling process (NYSDEC, 2011). Brine scales often interfere with the returns process as they

greatly narrow the width of the bore hole and pipe. This issue is alleviated with the addition of additives

such as ammonium chloride to the drilling fluid mixture. Classified as solids, brine scales may also be

disposed of along with drill cuttings (NYSDEC, 2011).

Waste Treatment, Reuse and Disposal Options

Treatment and disposal of solid waste from UGWD is generally achieved by sending the wastes to

landfills, a treatment facility, or a Class II injection well.

Beneficial Uses

Road Application (formation water only)

The states that allow the spreading of liquid wastes generated during UGWD generally allow the

spreading of only the formation water. This is the portion of the produced water considered in this risk

assessment.

Dust control is defined in the 2011 Maryland Standards and Specifications for Soil Erosion and Sediment

Control as “controlling the suspension of dust particles from construction activities.” The purpose of

dust control is to “prevent blowing and movement of dust from exposed soil surfaces to reduce on and

off-site damage including health and traffic hazards.” Dust control measures must be employed to any

“areas subject to dust blowing and movement where on and off-site damage is likely without

treatment.” The following substances can be used for dust control: mulches, vegetative cover, tillage

(brings heavier dirt clumps to the surface), irrigation (water), barriers such as silt fences, and chemical

6

treatment” This assessment applies the same definition to post-construction or other applications of

materials to surfaces for the purpose of dust control.

The State Highway Administration (SHA) Salt Management Plan, legislated in 2010 House Bill 0903 and

Senate Bill 0775, defines brines as a liquid anti-icing agent that SHA and other agencies use prior to

winter storm events. The brines are a pre-treatment practice intended to keep ice from bonding to

pavement facilitating easier snow removal. Brines can also be mixed with road salts to better facilitate

deicing operations (MSHA).

Agricultural Soil Amendments

In this assessment agricultural soil amendments refer to the one-time application of drilling muds to a

field that is, and will continue to be, used to grow crops. Bentonite clays can and have been used in less

developed countries and rural areas for soil amendments. The clays themselves are cheap and readily

available in large deposits all over the world. In general, a decline in organic matter minimizes soil’s

capacity to retain nutrients (fertilizer). Bentonite helps the soils to retain the cation exchange capability

aiding in the retention of fertilizers and other nutrients, and minimizing the potential for nutrient loss

through leaching (Czaban J. et al., 2013).

Road construction (cuttings)

The drilling industry is rapidly identifying ways in which wastes can be put to beneficial use, rather than

disposed of at a landfill or some other facility. Cuttings may potentially be used in the construction of

access roads or well pads. Other possible construction applications include use in road pavements,

bitumen, and asphalt or use in cement manufacture (Haut, 2012).

Waste disposal methods

On-site Disposal

On-site disposal is the permanent placement of solid drilling waste into a pit within the disturbed area

used for HVHF operations. Once filled, the area is reclaimed to prevent erosion.

Landfill Disposal

7

Landfills are facilities designed for the disposal of municipal and industrial wastes. Generally waste

materials are placed in lined pits called cells and covered at regular intervals. In Maryland, municipal,

industrial and rubble landfills must have liners and leachate collection systems.

Land farming

Land farming can be considered both a treatment and disposal method. The wastes are applied to the

surface so that organisms in the soil will metabolize, transform and assimilate waste constituents. The

surface can be tilled and water, nutrients, manure, etc. may be added to speed the microbial action.

(DWMIS).http://web.ead.anl.gov/dwm/techdesc/land/index.cfm

Out-of-State Transport

Out-of-state transport is the final disposal or beneficial use of waste material generated by the UGWD

process wholly outside of the state of Maryland.

Assessment of Risks

Although the waste from UNGD is generally excluded from the definition of hazardous waste, solid

waste regulations apply to their handling and disposal. Beneficial uses must be legitimate and not

present a hazard.

Liquids - Road Application (formation water only)

Activity & Risk Identification

The salt in formation water, like any brine, is easily mobilized from road surfaces with precipitation,

running off into surface waters or infiltrating into ground waters (SHA). Salt can harm plants and aquatic

life, wildlife and pets, adversely affect the soil, and damage infrastructure and vehicles.

In a comment response to New York’s consideration of formation brine as a beneficial use, EPA stated

that “produced water may still contain some of the chemicals used in the hydraulic fracturing fluids if

not all the fluids returned in the initial flowback period. Moreover, the actual concentration and/or

radioactivity of contaminants in the produced water spread on land or roads would be unknown at any

given time since the amount and type of contaminants in produced water varies from well to well and

even in the same well over time unless each truckload is tested which would be a monumental task

given the amount of produced water that is expected to be generated from Marcellus and Utica shale

gas extraction and available for road spreading. In addition, road spreading of any type of natural gas

non-domestic wastewater could lead to violations of the Clean Water Act’s no direct discharge

prohibition due to runoff of contaminated storm water and snowfall. Furthermore, such a practice,

http://web.ead.anl.gov/dwm/techdesc/land/index.cfm

8

depending on the make-up of the soils along the roadway, could lead to surface infiltration of the

produced water and risk contamination of the underlying aquifer.” (EPA, 2012).

There are no State referenced controls incorporated into COMAR, beyond dust control during

construction, which regulates these activities. Outside of state highways, the purview for such

operations falls to the counties. The Salt Management Plan mandated by legislature consists of

guidance and recommended BMPs, and each county and municipality must develop their own plans.

Risk Mitigation (Current Regulation & Proposed BMPs)

Maryland proposed the following BMPs that are relevant to the management and disposal of produced

water:

o The application for a well permit must include a plan that addresses waste handling, treatment and disposal.

o Flowback, produced water, residue from treatment of flowback and produced water should be tested for radioactivity and disposed of in accordance with law.

o Flowback and produced water shall be recycled to the maximum extent practicable. Unless the applicant can demonstrate that it is not practicable, the permit shall require that not less than 90 percent of the flowback and produced water be recycled, and that the recycling be performed on the pad site of generation.

o The permittees must keep a record of the volumes of wastes and wastewater generated on-site, the amount treated or recycled on-site, and a record of each shipment off-site, including confirmation that the full shipment arrived at the facility. The records may take the form of a log, invoice, manifest, bill of lading or other shipping documents

Risk Assessment

The necessary implication of these recommendations is that flowback and produced water may not be

applied to roads for de-icing. On a case-by-case basis, if the waste management plan proposes to use

flowback for de-icing, the Department will consider whether the constituents and concentrations of the

flowback are suitable as a substitute for commercial de-icing formulations. Because of the requirement

for recycling, the probability of this use is low, and the consequence of this use is moderate because it

could have considerable adverse impact on people or the environment in a localized area.

Agricultural Soil Amendments


Application of drilling muds to land meant for food or forage production could introduce pollutants and

heavy metals into humans or animals consuming the crops or forage. The pollutants could also run off or

infiltrate, degrading surface water or ground water.

9

While bentonite may be used as a soil amendment, it has also been documented that the bentonite clay

structure and cation orientation allow it to readily adsorb heavy metals from solution. Montmorillonite

showed good adsorbance for removal of toxic heavy metals as (Cd, Cr, Co, Cu, Fe, Pb, Mn, Ni and Zn).

The overall effectiveness of the adsorption depends on a number of factors such as pH and the overall

concentration of metals in solution (Vega J.L et al., 2014).

Bentonite based drilling muds that have come into contact with formation brines early in the well

drilling process will most likely contain lower levels of metals as the TDS and salinity of the brines

increases in the latter drilling stages (NYSDEC, 2011, 6-117; Haluszcak et al. 2012). However, there are

several types of bentonite clays, calcium bentonite, potassium, and sodium bentonite, the latter being

used in UGWD operations. This type of bentonite clay is not favored or very suitable as a soil

amendment because of the high water absorption during the drilling process. This absorption makes

these types of muds difficult to incorporate into soils and may create a barrier preventing water

infiltration.


Maryland proposed the following BMPs that are relevant to the use of drilling mud as an agricultural soil

amendment:


o Drilling muds should be tested for radioactivity and disposed of in accordance with law. o The permittees must keep a record of the volumes of wastes and wastewater generated on-site,

the amount treated or recycled on-site, and a record of each shipment off-site, including confirmation that the full shipment arrived at the facility. The records may take the form of a log, invoice, manifest, bill of lading or other shipping documents

Risk Assessment

The necessary implication of these recommendations is that drilling muds may not be applied to

agricultural land as a soil amendment. On a case-by-case basis, if the waste management plan proposes

to use drilling muds for this purpose, the Department will consider whether the constituents and

concentrations of the drilling muds are suitable for that use. The probability that bentonite clay would

be used as an agricultural soil amendment is low because it is not well suited for this application. If it

were used, there could be a considerable adverse impact on people and the environment in a localized

area. For this reason, the consequence is judged to be moderate.

Solids - Road construction (cuttings only)


Use of cuttings for road construction would pose a risk to people and the environment if the cuttings

were to leach pollutants into surface or ground water due to run-off and infiltration. This could degrade

habitat and drinking water.

10

Industry case studies have demonstrated that cuttings could be treated to render them safe for handling

and recycling. Some methods considered involve an encapsulation process that binds the pollutants of

concern, while others have found success by thermally treating the cuttings at a facility such as an

asphalt plant. The thermal treatment process may release VOCs, but will be mitigated by the emissions

standards established for such a facility. Once treated, the resulting material is relatively clean (DWMIS;

Haut, 2012; Burnett & Platt, 2014). Although feasible, the development of such technologies is limited

to a few case studies, with even fewer companies possessing the necessary technology. Texas and

Louisiana are currently the only states that allow the use of recycled UGWD cuttings as road material.

Use in these states is limited to UGWD pads and access roads. Several other states are considering the

prospect pending further research (Haut, 2012).


The best practices report did not address the possibility of using cuttings for road construction. It

considered landfilling and on-site disposal.

Maryland proposes the following BMPs that are relevant to road applications of cuttings:


o The cuttings must be tested for radioactivity other contaminants, including sulfates and salinity, before disposal and disposed of in accordance with law.

Risk Assessment

Cuttings material from the fresh water aquifer drilling phase of UGWD could potentially be recycled as

road material as long as the cuttings themselves meet current use guidelines for road base/road

construction material. It is unlikely that cuttings generated later in the process could be reused as road

or construction material since the necessary technology to render it innocuous is still in the very early

development stage.

As with drilling mud, if the waste management plan proposes to use cuttings for road construction, the

Department will consider, on a case-by-case basis, whether the constituents and concentrations of the

cuttings are suitable for that use. . The probability that cuttings capable of leaching pollutants would be

used for road construction is low because the cuttings must be tested before approval could be granted.

If it were used and contaminants leached, there could be a considerable adverse impact on people and

the environment in a localized area. For this reason, the consequence is judged to be moderate.

11

On-site Disposal


On-site disposal is the permanent placement of solid drilling waste into a pit or depression in the

ground, after which it is covered with soil and reclaimed. On-site disposal of cuttings would pose a risk

to people and the environment if the cuttings were to leach pollutants into the soil or ground water.

This could degrade the soil and ground water. If contaminated ground water is used for drinking water,

human health could be adversely affected.

Cuttings generated from the uppermost part of the vertical borehole are more likely to be considered

for on-site disposal because the uppermost portion is less likely to have high salt content or NORM.

Once cuttings have come into contact with the oil-based muds they will most likely not be suitable for

on-site burial (NYSDEC, 2011, p. 5-129).


Maryland proposes the following BMPs that are relevant to on-site disposal of cuttings:



Risk Assessment

During the pit filling process water may accumulate or become separated from the cuttings due to

settling. The probability of this occurring decreases dramatically if the cuttings are mixed with bulking

materials like fly ash. Stormwater is most likely the primary source of water that may accumulate in the

on-site disposal pit (DWIMS). There is some potential to impact ground waters associated with the on-

site burial method.

If the waste management plan proposes to dispose of cuttings on-site, the Department will consider, on

a case-by-case basis, whether the constituents and concentrations of the cuttings are suitable for that

use. . The probability that cuttings capable of leaching pollutants would be buried on-site is low because

the cuttings must be tested before approval could be granted. If it were used and contaminants

leached, there could be a considerable adverse impact on people and the environment in a localized

area. For this reason, the consequence is judged to be moderate.

Disposal in a Landfill

If landfills are not properly designed, constructed, and operated, leachate could contaminate ground

water. If waste materials are not properly spread, compacted and covered, wastes could be exposed to

precipitation leading to contaminated runoff.

12


Maryland has a robust permitting program for landfills. In Maryland, municipal, industrial and rubble

landfills are required to have liners and leachate collection systems that facilitate the collection of

leachate and prevent migration of pollutants out of the landfill to adjacent subsurface soil, ground

water, and surface water. The landfills are also required to do routine ground water monitoring to

detect any releases. Permits for the landfills establish limitations on what the landfills may accept for

disposal. (MDE & DNR, 2014).

Maryland proposes the following BMPs that are relevant to disposal of cuttings in a landfill:



Risk Assessment

Because of Maryland’s regulatory requirements for landfills, the probability that contaminants from

cuttings would be released from a permitted landfill is low. Leachate collected from the landfill will

contain pollutants, but the testing of the waste for radioactivity and other contaminants before

landfilling will reduce this risk. Exposure of landfill workers or the public to the waste, or release of

pollutants due to a failure of the liner or leachate collection system or improper handling of leachate

could cause an adverse affect on people or the environment, although this would be localized. For this

reason, the consequence is judged to be moderate.

Land farming

If done improperly, land farming can result in a buildup of salts, hydrocarbons, and heavy metals in the

soil, leading to reduced productivity and contamination of ground water and surface water.

This could cause harm to people and the environment. Humans and animals could come into contact

with the wastes while they remain on the surface.


Current Maryland regulations provide “Land farming of cuttings shall be permitted only on approval

from the Department and shall require: (1) Soils analysis before site preparation; (2) Cuttings analysis as

directed by the Department; and (3) Post land farming soils analysis.” (COMAR 26.19.01.10W). The land

farming is to occur in areas of disturbance (COMAR 26.19.01.06F(2)(g)).

Maryland proposes the following BMPs that are relevant to on-site disposal of cuttings:


13


Risk Assessment

If the waste management plan proposes to land farm cuttings on-site, the Department will consider, on

a case-by-case basis, whether the constituents and concentrations of the cuttings are suitable for land

farming. The probability that cuttings capable of leaching pollutants would be land farmed on-site is low

because the cuttings must be tested before approval could be granted. If it were used and

contaminants leached, there could be a considerable adverse impact on people and the environment in

a localized area. The location restrictions and setbacks would limit exposure. For this reason, the

consequence is judged to be moderate.

Out-of-State Transport

Disposal out of state presents no risk to Marylanders. The laws and regulations of the federal

government and other states can be assumed to be adequately protective.

Conclusion

The probability of harm associated with treatment or disposal of wastes from HVHF is low. The

consequence if the harm were to occur is moderate. The overall risk ranking is low.

14

Summary Table of Probability, Consequence and Risk Ranking

Operation Occurrence Environmental Impact

Probability Consequence Risk Ranking

Road application of brine

Release of contaminants in the brine

Harm to plants and aquatic life, wildlife and pets, adverse effect on soil, and damage infrastructure and vehicles

Low Moderate Low

Agricultural Soil Amendment

Release of contaminants from drilling mud

Introduction of pollutants into the human or animal food chain; pollutants could run off or infiltrate, degrading surface water or ground water.

Low Moderate Low

Road construction

Release of contaminants from cuttings

Contamination of surface and ground water, degradation of habitat and drinking water

Low Moderate Low

On-site disposal

Release of contaminants from cuttings

Degradation of the soil ,ground water and drinking water

Low Moderate Low

Disposal in a landfill

Release of contaminants by stormwater runoff and contamination of leachate

Soil, surface water and ground water

Low Moderate Low

Land farming Release of contaminants and buildup of salts, hydrocarbons, and heavy metals in the soils

Reduced productivity of soil, surface water and ground water

Low Moderate Low

Disposal out of state

Does not occur in Maryland

NA NA NA NA

15

References Burnett, D.B. and F.M. Platt. Low Impact Testing of Oil Field Access Roads: Reducing the Environmental Footprint in Desert Ecosystems.

Research Partnership to Secure Energy for America. January 2014. <http://www.rpsea.org/files/3706/>

Czaban, J., et al. “Effects of Bentonite Addition on Sandy Soil Chemistry in a Long-Term Plot Experiment (I); Effect on Organic Carbon and Total

Nitrogen.” Polish Journal of Environmental Studies Volume 22, No. 6 (2013): 1661-1667. Print.

“Department of the Environment.” 26 “COMAR” 13.02.04-1(A(5))

---. 19.01.10 Web.

Hackney, J. and Mark R. Weisner. Duke University. Cost assessment of Produced Water Treatment. North Carolina: Durham, 1996. Print.

Haluszczak, Lara O., Arthur W. Rose and Lee R. Kump.. “Geotechnical evaluation of flowback brine from Marcellus gas wells in Pennsylvania,

USA.” Applied Geochemistry, Jan. 2013: 55-61. Print.

Haut, Richard. “Environmentally Friendly Drilling Systems Program. RPSEA EFD Project 08122‐35.” Texas: Houston, 2012. Print.

King, George. E. Society of Petroleum Engineers. Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter,

Investor, University Researcher, Neighbor and Engineer Should Know About Estimation Frac Risk and Improving Frac Performance in

Unconventional Gas and Oil Wells. Hydraulic Fracturing Teleconference, Woodlands, Texas. 2012.

“Protection of Environment.” 40 “CFR” 403.5. 2000.

---. 435.23. 2000.

---. 261.4(B)(5)

Maguire-Boyle and Barron. Organic compounds in produced waters from shale gas wells, Environmental Science Process & Impacts, Royal

Society of Chemistry. 2014.

Maryland Department of the Environment(MDE). 2011 Standards and Specifications for Erosion and Sediment Control. 2011. Print.

Maryland Department of the Environment (MDE) and Maryland Department of Natural Resources (MDNR). Marcellus Shale Safe Drilling

Initiative Study: Part II. Interim Final Best Practices. Jul. 2014. Web.

<http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf >

---. NPDES Industrial & General Surface Water Discharge Permits. Web. 29 April, 2014. <http://www.mde.state.md.us>

---. Response to Comments, Waste disposal. 2014. Web.

<http://www.mde.state.md.us/programs/Land/mining/marcellus/Documents/7.10_Version_Final_BP_Report.pdf>

---. Solid Waste Management in Maryland. Web. 29 April, 2014. <http://www.mde.state.md.us>

Maryland State Highway Administration (MSHA). Statewide Salt Management Plan. 2007. Print.

Materials Which Are Not Solid Waste. Division of State Documents. COMAR 26.13.02.04 (January 18, 1982).

New York State Department of Environmental Conservation. Supplemental Generic Environmental Impact Statement on the Oil, Gas and

Solution Mining Regulatory Program: Well Permit Issuance for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop

the Marcellus Shale and Other Low-Permeability Gas Reservoirs. New York: Albany, 2011. Print.

http://www.mde.state.md.us/

http://www.mde.state.md.us/

16

Oil and Gas Exploration and Production. Division of State Documents. COMAR 26.19.01 (November 25, 1991).

“Oklahoma Gov. Mary Fallin creates seismic activity council”, The Oklahoman, September 4, 2014, < http://newsok.com/oklahoma-gov.-mary-

fallin-creates-seismic-activity-council/article/5338886>

Railroad Commission of Texas, proposed rule http://www.rrc.state.tx.us/media/22606/prop-amend-3-9and3-46-seismic-activity-sig-

august2014.pdf

United States Department of Energy. Drilling Waste Management Technology Descriptions. Washington: GPO, 2008. Print.

United States Environmental Protection Agency. Crude Oil and Natural Gas Wastes. Web. 24 April, 2014. <http://epa.gov>

---. EPA Comments on Revised Draft NYDEC Revised dSGEIS for Horizontal Drilling and High-Volume Hydraulic Fracturing to Develop the

Marcellus Shale and Other Low-Permeability Gas Reservoirs (Enclosure). 2012. Print.

---. Hazardous Waste Recycling Regulation. Web. 24 April, 2014. <http://epa.gov>

---. Non-Hazardous Waste Management Hierarchy. Web. 24 April, 2014. <http://epa.gov>

Vega, J.L, et al. “Bentonites as adsorbents of heavy metals ions from mine waste leachates: Experimental data.” 9th International Mine Water

Congress, 2005. Web. 24 April 2014. <http://www.imwa.info>



http://www.rrc.state.tx.us/media/22606/prop-

http://epa.gov/

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http://epa.gov/

http://www.imwa.info/

1

Appendix J

Acronyms

AGC Annual guideline concentrations (New York)

API American Petroleum Institute

ATV All terrain vehicle

BAT Best available technology

BMP Best management practice

BTEX Benzene, toluene, ethylbenzene and xylenes

CAA Clean Air Act

CDC Centers for disease control

CFR Code of Federal Regulations

CGDP Comprehensive Gas Development Plan

CMV Commercial motor vehicle

COMAR Code of Maryland Regulations

dB Decibel

dBA Decibles, with a weighted scale (dBA) to account for relative loudness as perceived by the human ear

DE Diesel exhaust

DNR Maryland Department of Natural Resources

DOT Department of Transportation

EIS Environmental Impact Statement

EPA The Environmental Protection Agency

FHWA Federal Highway Administration

FMCSA Federal Motor Carrier Safety Administration

FR The Federal Register

Fed. Reg. The Federal Register

ft Feet

gal Gallon

Gg Gigagrams

HAP Hazardous air pollutants

HVHF High volume hydraulic fracturing

IBCs Intermediate bulk containers

IPIECA International Petroleum Industry Environmental Conservation Association

km kilometer

MDE Maryland Department of the Environment

mgd Million gallons per day

NAAQS National Ambient Air Quality Standards

NESHAP National Emissions Standards for Hazardous Air Pollutants

NGLs Natural gas liquids

2

NGWA National Ground Water Association

NIH National Institutes of Health

NIOSH National Institute for Occupational Safety and Health

NO2 Nitrogen oxide

NORM Naturally occurring radioactive material

NOx Nitrogen oxides (NO and NO2)

NYSWRI New York State Water Resources Institute

OGP The International Association of Oil & Gas Producers

PA PUC Pennsylvania Public Utility Commission

PM10 Particles less than 10 micrometers in diameter

PM2.5 Fine particles (less than 2.5 micrometers in diameter

PNAS Proceedings of the National Academy of Sciences

POTW Publicly owned treatment works

psi Pounds per square inch

RA Risk assessment

REC Reduced emissions completions

RUMA Road use and maintenance agreement

SEAB Secretary of Energy Advisory Board

SIP State Implementation Plan

SO2 Sulfur dioxide

TENORM Technologically enhanced naturally occurring radioactive material

Tier II stream Streams designated by MDE where water quality is better than the minimum requirements; sometimes called “high quality waters”

tpy Tons per year

TSS Total suspended solids

UGWD Unconventional gas well development

ULSD fuel Ultra-low sulfur diesel fuel

Use III stream

Natural trout streams

Use IV streams

Recreational trout waters

VOCs Volatile organic compounds

WHO World Health Organization

yr Year

maryland risk assessment of shale drilling & fracking

News & Politics