Email: sharvey@mtaonline.net Phone: (907) 694-7994 

 Fax: (907) 694-7995 

PO Box 771026 

Eagle River, Alaska 99577 

2009 NYS DSGEIS 

Draft Supplemental Generic 

Environmental Impact Statement 

On the Oil, Gas & 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

Review of DSGEIS and Identification of Best Technology 

and Best Practice Recommendations 

Report to: 

Natural Resources Defense Council (NRDC)

Prepared by: 

Harvey C onsulting, LLC.

Oil & Gas, Environmental, Regulatory Compliance, and Training

December 28, 2009
NYS DSGEIS Page 2 of 39 

Contents 

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

1. Scope of DSGEIS............................................................................... 3 

2. NYS Regulations Needed to Guide Marcellus Shale Exploration & Development ... 6 

3. Drilling Mud Composition and Drilling Waste Disposal.................................. 9 

4. Disposal of Drilling & Production Waste & Equipment Containing NORM .......... 13 

5. Casing and Cementing Requirements ....................................................... 16 

6. Flaring, Venting and Fugitive Emissions.................................................... 17 

7. Hydrogen Sulfide ............................................................................... 19 

8. Seismic Data Collection ........................................................................ 19 

9. Corrosion and Erosion Control ................................................................. 20 

10. Spill Prevention ......................................................................................... 21 

11. Spill Response ....................................................................................... 23 

12. Fuel Selection ......................................................................................... 23 

13. Hydraulic Fracture Design and Monitoring................................................. 24 

14. Hydraulic Fracture Treatment Additive Limitations ....................................... 30 

15. Hydraulic Fracture Fluid Flowback Surface Impoundments .............................. 31 

16. Chemical Tank Containment .................................................................. 34 

17. Reserve Pit & Impoundment Use and Liner Quality ........................................ 35 

18. Wellbore Plugging and Abandonment Requirements .................................... 36 

19. Well Control & Emergency Response Planning .......................................... 37 

20. Hazardous Air Pollution Control ............................................................ 37 

21. Compressor Stations, Pipelines, and Gas Processing Facilities ......................... 39 

22. NYSDEC Inspection and Enforcement Program .......................................... 39 

23. Financial Assurance Amount ................................................................. 39 
NYS DSGEIS Page 3 of 39 

Introduction 

This analysis responds to the Natural Resources Defense Council’s (NRDC) request for a review of the 

New York State (NYS) September 2009 Draft Supplemental Generic Environmental Impact Statement 

(DSGEIS) on the Oil, Gas & Solution Mining Regulatory Program Well Permit Issuance for Horizontal 

Drilling and High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other LowPermeability Gas Reservoirs. 

NRDC requested a technical review of the DSGEIS to determine if best technology and practices 

protective of the environment were included. NRDC and its partners have commissioned additional 

experts to make recommendations on the protection of other resources. Therefore this list of 

recommendations is not exhaustive, and is complementary to the work assigned to other experts 

reviewing the DSGEIS. A complete list of best technology and practices recommended by the experts can 

be found in the summary cover letter submitted by AKRF, Inc. to the New York State Department of 

Environmental Conservation (NYSDEC) during the DSGEIS public comment period. 

This report makes recommendations for improving the NYS DSGEIS analysis. This report also makes 

recommendations for how to more formally adopt and require best practices in NYS regulations. 

Specific recommendations are highlighted in a blue text box. 

1. Scope of DSGEIS 

Recommendation No. 1: The DSGEIS scope should be limited to analysis of the Marcellus 

Shale Gas Reservoir. The Marcellus Shale is a substantial accumulation, and warrants its own EIS 

analysis. Additional information and analysis is needed to examine the impacts of exploring and 

developing other low-permeability gas reservoirs. 

NYSDEC proposes that the DSGEIS cover all horizontal drilling and high-volume hydraulic fracturing in 

all low-permeability gas reservoirs in NYS; yet, only the Marcellus Shale Gas Reservoir is studied in 

detail. The DSGEIS is incomplete for all other low-permeability gas reservoirs. 

 

The DSGEIS provides some information on the Utica Shale Gas Reservoir (mostly in the form of 

geologic assessment), but it does not examine in detail the impacts of drilling or high-volume hydraulic 

fracture treatments on the Utica Shale or other low-permeability gas reservoirs in the region. 

Chapter 4 provides a geologic description of the Marcellus and Utica shale gas reservoirs; however, no 

other low-permeability gas reservoirs are examined. 

Chapters 5 and 6 provide an analysis of drilling, fracturing, and development approaches in the Marcellus 

Shale Gas Reservoir. Yet, Chapters 5 and 6 are essentially silent on how the Utica Shale Gas Reservoir 

would be developed. No other low-permeability gas reservoirs are examined. 

Technical reports, which were provided by NYSDEC’s consultants as supporting documents for the 

DSGEIS, focus on Marcellus Shale development; they do not provide technical data about or support for 

development of other low-permeability gas reservoirs in the region. 
NYS DSGEIS Page 4 of 39 

The Utica Shale Gas Reservoir is almost twice as deep as the Marcellus Shale Gas Reservoir at its deepest 

point in southern NYS. The Utica Shale dips to 9,000’ deep,1

 while the Marcellus Shale is approximately 

5,000’ deep.2

 Utica Shale wells will take longer to drill than Marcellus Shale wells, generating more air 

pollution and drilling waste. Utica Shale development will also require more resources and equipment. 

Therefore, the maximum impact assessment for a Marcellus Shale well is not sufficient to examine the 

maximum impact for a Utica Shale well. 

Low-permeability gas reservoirs that are present at depths shallower than the Marcellus Shale were not 

studied in any detail, and there is insufficient information in this EIS to justify any development at this 

time. 

Best technology and best practices, in many cases, are gas reservoir specific. Because the DSGEIS does 

not contain information on the depth, type, activity or equipment requirements for the general category in 

DSGEIS called “other low-permeability gas reservoirs,” it is not possible to determine if the maximum 

impact assessment for a Marcellus Shale well sufficiently covers the maximum impact from “other lowpermeability gas reservoirs.” Nor is it possible to determine whether best technology and practices 

developed for the Marcellus Shale would apply. 

Recommendation No. 2: There is insufficient data provided on the Marcellus Shale Gas 

Reservoir to support a statewide exploration and production plan. The dataset provided by 

NYSDEC, in this DSGEIS, is equivalent to early exploration. Additional information is needed 

to support site-specific production/development scenarios for the Marcellus Shale Gas Reservoir. 

NYSDEC should consider either: 

(1) Narrowing the scope of this DSGEIS to exploration activities, and baseline study work, and 

complete a separate future EIS when additional exploration data is available to support a 

production/development case; or 

(2) Clearly outline in this DSGEIS the data set that must be obtained, and analyses that must be 

performed during exploration, to obtain sufficient information to support a 

production/development case. The DSGEIS should then establish a process for conducting a 

site-specific environmental assessment for each production/development well site based on 

that data collected during the exploration phase. 

During the scoping analysis for this DSGEIS, the paucity of exploration data and baseline study work on 

the Marcellus Shale was not evident. NRDC, and its partners, supported alternatives to examine 

statewide production/development scenarios assuming exploratory work and baseline datasets were 

available to NYSDEC to support such an analysis. It was not until the DSGEIS was published in 

September 2009 that the paucity of data became patently obvious. 

Not only is there insufficient exploration data and baseline study work to support a 

production/development case for the Marcellus Shale on a statewide basis, the DSGEIS also made it clear 

that there is insufficient infrastructure, support facilities, expertise and agency oversight systems in place 

to support large-scale, statewide development of the Marcellus Shale. While there may be small sitespecific areas within NYS that have more tightly refined exploration data that could possibly support a 

small production/development case, this is certainly not true for all of NYS. The statewide dataset 

 

1

 DSGEIS, p. 4-6. 

2

 DSGEIS, p. 4-15.
NYS DSGEIS Page 5 of 39 

provided by NYSDEC, in this first draft, is equivalent to early exploration; it does not support a statewide 

production/development plan. 

NYS’s attempt to complete a statewide EIS to cover all future Marcellus Shale gas development is an 

enormous task. The first draft of the DSGEIS clearly demonstrates that there is insufficient data to 

complete this analysis. Because there is insufficient data to support a high-quality, site-specific scientific 

and technical assessment of Marcellus Shale gas production/development scenarios on a statewide basis, 

NYSDEC should consider either limiting this DSGEIS to exploration activities or should establish a 

process whereby additional data can be collected during exploration to support future 

production/development proposals. 

Gas resource development occurs in two distinct phases: (1) exploration and (2) production; commonly 

referred to as the upstream Exploration & Production (E&P) sector, to distinguish between downstream 

activities such as refining and marketing. Exploration activities are completed to locate the hydrocarbon 

resources and collect sufficient baseline data to determine whether the hydrocarbon resources can be 

safely, and economically, developed. Exploration typically includes single wells and numerous studies. 

Most commonly, an EIS is completed during the pre-exploration (leasing phase) to establish exploration 

limits, and to determine the baseline data that should be collected to guide future production/development 

opportunities. If data collected during exploration supports a production/development scenario, then 

larger scale production (multiple wells, on larger drill sites, and surface processing and distribution 

facilities) may be needed to develop the resource. Commonly, a full environmental assessment of the 

production/development scenario is the next step after exploration activities are completed. Site-specific 

production/development scenarios are typically prepared by the operator, in support of its proposed 

project, and are supported with high-quality, site-specific scientific and technical information to address 

the unique aspects of that project. 

Because NYSDEC’s DSGEIS attempts to combine both exploration and production approval into one 

EIS, substantially more information is required to support the EIS. And, in many cases, the data has not 

been collected because the exploratory work has not been completed. For this reason, the exploration and 

production EIS processes are very commonly separated throughout the United States. For example, the 

U.S. Minerals Management Service (MMS), which is responsible for developing all of the U.S. oil and 

gas resources in the Outer Continental Shelf, sets forth a two step process.3

 

• First, an environmental analysis is required to support the exploration phase. Based on that analysis 

and the sufficiency of the Exploration Plan prepared by the applicant, MMS issues an Exploration 

Plan Approval allowing operators to drill exploratory wells to delineate the oil and gas reservoir, 

and collect additional information that can support a Development and Production Plan and EIS. 

• Second, an environmental analysis is required to support the production phase. Based on that 

analysis and the sufficiency of the Development and Production Plan, MMS issues a Development 

and Production Plan Approval. 

Other oil and gas producing states, similarly, have regulations that provide for a step-wise approval 

process transitioning from leasing to exploration, and then to production and development. For example, 

Alaska follows a similar process as the MMS.4

 Alaska requires a Best Interest Finding document to be 

 

3

 MMS Regulations for Oil and Gas and Sulphur Operations in the Outer Continental Shelf. 30 C.F.R. pt. 250, 

Exploration and development are defined in 30 C.F.R. § 250.105. See 43 U.C.S. § 1340 and 30 C.F.R. §§ 250.211 

to .235; 250.280 to .285 for Exploration Plan requirements. See 43 U.S.C. § 1351 and 30 C.F.R. §§ 250.241 to 

.273; 250.280 to .285 for Development and Production Plan requirements. 4

 See 20 Alaska Admin. Code §§ 25.005, .990 (distinguishing exploration and development wells). 
NYS DSGEIS Page 6 of 39 

prepared before an area is even leased.5 This is essentially a state EIS process conducted prior to 

exploration. Once the leases are sold by the state, an exploration permit can be obtained to just drill the 

exploration wells and conduct studies.6

 Drilling additional wells, and developing surface facilities 

requires a development plan and full environmental assessment (operators must put a complete package 

together from drilling and all the surface facilities right up to where they connect into a sales line).7

 This 

stepwise approach allows for responsible development to proceed in areas where there is sufficient data to 

support the project, and requiring additional study and exploration in areas that are not well understood. 

While state regulations vary in procedural detail, this same basic approach is common, allowing 

exploratory operations to collect sufficient data to support a thorough, high-quality production and 

development assessment. If there is sufficient information available to support both exploration and 

production, it may be possible to permit both simultaneously, but this approach is uncommon. 

NYSDEC’s attempt to combine both exploration and production operations into one analysis has 

complicated the assessment and created an unmanageably large and complex analysis that is unsupported 

by the limited amount of currently available data. 

While the lack of data on the Marcellus Shale may have been self evident to NYSDEC, it was not to the 

public, and NYSDEC should have disclosed this problem during scoping, allowing other alternatives to 

be considered. At this point, there a couple recommended options for proceeding: 

• One alternative is to narrow the scope of this EIS to exploration of the Marcellus Shale. At some 

point in the future, when sufficient information is collected, an additional EIS to support the 

production/development phase of the Marcellus Shale development can be drafted. 

• Alternatively, the DSGEIS can attempt to combine exploration and production phases, but clearly 

define the data that must be obtained, and analyses that must be performed during exploration, to 

obtain sufficient information to support a production/development case. The DSGEIS could 

establish a process for conducting a site-specific environmental assessment for each 

production/development well site based on that data collected during the exploration phase. 

2. NYS Regulations are Needed to Guide Marcellus Shale Exploration & 

Development 

Recommendation No. 3: NYSDEC should update its regulations to include best technology and 

best management practices for oil and gas exploration and production in general, and more 

specifically for shale gas development. Oil and gas exploration and production should not be 

managed using out-of-date regulations, augmented by a patchwork of permit conditions and 

guidance memoranda. An updated regulatory framework provides: operators with clear, 

consistent rules to work from; NYSDEC staff with simplified instructions for implementation; a 

public process for input; and a more orderly and safe exploration and development process for 

NYS. 

 

5

 Alaska Statute § 38.05.180. 

6

 Alaska Statutes § 38.05.131 to .134. 

7

 20 Alaska Administrative Code § 25.517. 
NYS DSGEIS Page 7 of 39 

This DSGEIS proposes to build on the existing 1992 Generic Environmental Impact Statement (GEIS) for 

oil and gas drilling in NYS by providing additional information on the Marcellus Shale reservoir and 

high-volume hydraulic fracturing. This approach does not address the fact that, since 1992, numerous best 

technology and best management practice improvements have been made to basic elements of the E&P 

industry. By relying on 1992-vintage decisions and technology as the foundation for Marcellus Shale 

development, NYS’s DSGEIS starts with an unstable foundation. Therefore, the first and most logical 

step in this analysis is to examine the basic elements of the 1992 GEIS and determine what new best 

technology and best practice improvements have been made since 1992, and update the foundation of the 

analysis. Then, and only then, can NYS build a well-supported incremental analysis that examines the 

impact of new techniques such as horizontal drilling and high-volume fracture treatments. 

The 1992 GEIS is based on oil and gas regulations, most of which were adopted in 1972. 1972 vintage 

regulations are clearly inadequate to guide shale gas development in 2010 and beyond. 

Since 1992, NYSDEC has found other gaps in NYS’s regulatory structure and has developed numerous 

guidance documents in an attempt to bridge the regulatory gap. 

Now in 2009, 17 years later (and 37 years after adoption of most of the existing regulations), NYSDEC is 

faced with antiquated regulations that do not address the decades of oil and gas best technology and best 

practice improvements. This situation is compounded by a patchwork of permit stipulations and guidance 

documents that attempt to regulate the oil and gas industry in NYS. 

NYSDEC’s 2009 DSGEIS further compounds the problem by adding another list of permit conditions 

(Appendix 10) for shale gas development, without taking the time to step back and develop an updated, 

comprehensive set of regulations to guide future oil and gas development in NYS. 

It is recommended that this DSGEIS conclude that it is time for NYS to revise its regulations to include 

best technology and best management practices for oil and gas exploration and production in general, and 

develop regulations specific to the shale gas. 

An updated regulatory framework provides: operators with clear, consistent rules to work from; NYSDEC 

staff with simplified instructions to implement; a public process for input; and a more orderly and safe 

exploration and development process for NYS. 

The current patchwork of permit conditions and guidance documents do not provide for adequate public 

input because permit conditions can be revised subsequent to completion of the EIS, and guidance 

documents do not go through public review. NYS law requires public input in the regulatory development 

process, and any subsequent amendment. 

Recommendation No. 4: Even if NYSDEC persists, without adequate data, in addressing both 

exploration and production in this SGEIS, the proposed supplementary permit conditions are 

incomplete and inconsistent with both some of the DSGEIS findings and best 

technology/practices for gas shale development. The “Proposed Supplementary Permit 

Conditions” should be renamed to serve as a “List of Regulatory Improvements Required to 

NYS’s Regulations.” This list should reflect the numerous recommendations herein and those 

substantive comments received by NYSDEC from others. The list should be used to revise the 

NYS regulatory framework, because the DSGEIS should appropriately serve as the basis for 

examining and improving NYSDEC’s regulatory program for shale gas. 
NYS DSGEIS Page 8 of 39 

There is a significant disconnect in the DSGEIS between the assumptions, analysis and mitigation 

measures discussion in Chapter 7 and the final Proposed Supplementary Permit Conditions for HighVolume Hydraulic Fracturing (Appendix 10). NYSDEC proposes to use this revised set of permit 

conditions to regulate industry; thus, it is critical that the conditions reflect the best technology and best 

practices (mitigation), making the end-product a useable tool for the regulator, the applicant and the 

public. 

As explained above, it is recommended that NYSDEC revise its regulations to include best technology 

and best management practices for oil and gas exploration and production in general, and shale gas 

development in particular. This approach provides the best, most comprehensive method of creating 

exploration and production stipulations, and is a substantial improvement over generating a patchwork of 

“proposed supplementary permit conditions” to bridge a known regulatory gap. This report, along with 

other reports submitted by NRDC and its co-signatories, provides specific recommendations for 

improving NYS’s oil and gas exploration and production regulations. 

As stated in the title, the purpose of this DSGEIS was to examine the “oil and gas and solution mining 

regulatory program,” with a goal of more specifically identifying regulatory improvements to NYSDEC’s 

regulatory program for shale gas, not to merely generate a list of permit conditions. 

Therefore, it is recommended that the “Proposed Supplementary Permit Conditions” be renamed to serve 

as a “List of Regulatory Improvements Required to NYS’s Regulations.” This list should be updated and 

complete, reflecting the numerous recommendations herein and those comments received by NYSDEC 

from others. The refined list should serve as a basis for revising the NYS regulatory framework, which is 

the next logical step. 

Recommendation No. 5: NYS’s regulations need to be revised to address Marcellus Shale gas 

development, provide a clear, complete list of prohibited activities, and describe maximum 

allowable levels of activities and expected mitigation. When codified in regulations, NYSDEC 

staff, the applicant, and the public will fully understand the “bottom-line” requirements. 

NYS’s regulations need to provide a clear, complete list of prohibited activities, and describe maximum 

allowable levels of activities. The regulations also need to include a clear description of expected 

mitigation. This approach facilitates implementation and enables NYSDEC staff, the applicant, and the 

public to fully understand the “bottom-line” requirements. 

In some cases, the DSGEIS proposes mitigation that is not carried through to the proposed permit 

conditions. In many cases, the DSGEIS describes limitations (e.g. maximum volume, duration, depth) to 

explain why NYSDEC believes the impact will be limited. Yet, often these limits are not translated into 

enforceable permit conditions. Without regulatory constraints, impacts from exploration and development 

activities will exceed those considered in the DSGEIS, and there may be undisclosed and unmitigated 

significant adverse environmental impacts. 

While not an exhaustive list, the short list provided below demonstrates the disconnect between the limits 

and assumptions found in the text of the DSGEIS and the requirements listed in the Proposed 

Supplementary Permit Conditions. Other examples are identified elsewhere in this report. None of these 

limits found in the text of the DSGEIS are set by permit condition:

• diesel-based fracture fluid is not allowed;8

 

8

 DSGEIS, p. 7-41. 
NYS DSGEIS Page 9 of 39 

• site-specific analysis is required for high-volume hydraulic fracture at depths less than 2,000’ 

TVD,9

 or if the distance between the target fracture zone and a fresh water supply is less than 

1,000’ TVD;10

• maximum hydraulic fracture size;11

• maximum three (3) days of flaring;12and, 

• maximum of 250 days of operation for drilling engines, maximum of 20 days for hydraulic 

fracturing engines, and maximum of 30 days of flaring in a given year.13

In other areas of the DSGEIS, the stated limits conflict. For example, Section 6.5.2.2 “Sources of Air 

Emissions and Operational Scenarios” states that the worst case scenario for emissions produced from a 

single well pad is a drilling rig in operation while an adjacent well is being completed, another well is 

being routed to flare, and an onsite line heater is in use. This maximum case air pollution scenario doesn’t 

take into account the possibility of a simultaneous drilling rig operation at the same well pad, which is 

discussed in Section 5.2.2: “One operator has stated that on a well pad where six or more wells are 

needed, it is possible that two triple-style rigs may operate concurrently.” Therefore, the maximum air 

pollution case would be the operation of two concurrent drilling rigs, not just one, unless simultaneous 

operation of two drilling rigs on a single pad is prohibited. Because there are no limits on the number of 

concurrently operating air pollution sources in the proposed permit conditions, significant potential 

adverse impacts have not been determined, and required mitigation has not been identified. 

The DSGEIS recommends in Chapter 7 that additional, more stringent permit conditions be added in 

some cases; however, these more stringent mitigation measures are not included in the Proposed 

Supplementary Permit Conditions (Appendix 10). For example, Section 7.1.3.4, p. 7-35, lists more 

stringent requirements in primary aquifers and unfiltered water supply areas, including: removal of fluids 

within 7 days of drilling and stimulation operations for each well; immediate fluid removal if operations 

are suspended; immediate fluid removal if the site is left unattended at any time; and removal of fluids 

within 7 days of completing drilling and stimulation operations at the last well on a pad. These more 

stringent requirements are not summarized in the proposed permit conditions for NYSDEC staff to select 

as an alternative to the 45-day timeframe allowed by proposed Permit Condition No. 16. 

3. Drilling Mud Composition and Drilling Waste Disposal 

Recommendation No. 6: NYS regulations should be revised to acknowledge and mitigate 

drilling mud pollution impacts, minimize drilling waste generation, limit heavy metal and NORM 

content, NORM, and establish best practices for collection, treatment and disposal of drilling 

waste. 

The 1992 GEIS allows drill cuttings to be buried onsite, and the DSGEIS is silent on the potential 

pollution impact from drilling muds. Current regulations incorrectly conclude that “drilling muds are not 

considered to be polluting fluids.” 6 NYCRR § 554.1(c)(1). This error should be corrected. 

Drilling muds are used to control the hydrostatic pressure in a wellbore. The most common weighting 

agent used is barite. U.S. Department of Energy studies show that barite contains mercury (1ppm-10ppm 

 

9

 TVD= True Vertical Depth. 

10 DSGEIS, p. 7-49. 

11 DSGEIS, p. 6-56. 

12 DSGEIS, p. 6-63. 

13 DSGEIS, p. 6-72.
NYS DSGEIS Page 10 of 39 

Hg, depending on its origin.)14 Mercury concentrations can be reduced by using thermal methods, 

leaching with dilute acids, or selecting barite with naturally occurring lower concentration levels of 

mercury.15 

The U.S. Department of Interior estimates that 0.8 metric tons of mercury is discharged into the Gulf of 

Mexico (GOM) annually (1839 lb Hg/yr) from mud disposed from drilling operations.16 This equates to 

approximately 1.69 lbs of mercury per well, for wells drilled to a total depth of approximately 12,000’. 

(1,091 wells/yr drilled in GOM))* (12,038 ft/well)*(140 lbs barite/ft)*(1x10-6 Hg/g barite)= 1,839 lb Hg/yr. 

(1,839 lb/Hg)/(1,091 wells) = 1.69 lbs of mercury per well. 

Using an average wellbore length of 5,000’ for a Marcellus Shale well, and a lower barite use rate of 100 

lbs/ft to account for lower expected pressures, the mercury content in the drilling mud is estimated at 

0.5- 5.0 lbs of mercury per well, depending on barite quality: 

1ppm Hg in barite= (1 Marcellus well)* (5,000 ft/well)*(100 lbs barite/ft)*(1x10-6 Hg/g barite) = 0.5 lb Hg/well 

10ppm Hg in barite= (1 Marcellus well)* (5,000 ft/well)*(100 lbs barite/ft)*(10x10-6 Hg/g barite) = 5.0 lb Hg/well 

Drilling muds may also contain the heavy metal cadmium, leading the EPA to establish cadmium 

concentration limits in drilling muds for muds disposed offshore.17 

The DSGEIS proposed permit conditions require a disposal plan pursuant to 6 NYCRR § 554.1(c)(1); 

however, the plan is not available for public review or input, so it is unclear what the plan will require. 

The DSGEIS explains that NYS solid waste management regulations at 6 NYCRR Chapter IV, 

Subchapter B (Solid Waste) provide the authority by which the state (through the Division of Solid and 

Hazardous Materials) establishes standards and criteria for solid waste management operations, including 

landfills and land application. However, the DSGEIS is unclear on what NYSDEC has deemed to be the 

best management practice for handling drilling waste. 

A recent U.S. Department of Energy review of NYS drilling waste disposal regulations concluded: 

“The [NYS] DEC has developed no regulations, policies, or guidelines governing slurry 

injection, subsurface injection, or annular disposal of drilling wastes and reserve-pit wastes.”18

NYSDEC has not established regulations to minimize the generation of drilling waste (e.g. reuse, 

recycle), nor has NYSDEC established limits on the heavy metal content of drilling mud additives. 

Proposed Permit Condition No. 2319 requires the use of a “closed loop tank system” instead of a reserve 

pit to manage drilling fluids and cuttings within a floodplain, but the DSGEIS not explain why a “closed 

 

14 http://www.fossil.energy.gov, “Mercury Removal from Barite for the Oil Industry.” 15 http://www.fossil.energy.gov, “Mercury Removal from Barite for the Oil Industry.” 16 http://www.gomr.mms.gov/homepg/regulate/environ/Hg%20discharge%20estimate.pdf. 17 U.S. Environmental Protection Agency, Development Document for Effluent Limitation Guidelines and New 

Source Performance Standards for the Offshore Subcategory of the Oil and Gas Extraction Point Source Category, 

EPA 821-R-93-003, 1993. 18 U.S. Department of Energy, Drilling Waste Management Information System, 

http://web.ead.anl.gov/dwm/regs/state/newyork/index.cfm.

19 DSGEIS, Appendix 10. 
NYS DSGEIS Page 11 of 39 

loop tank system” cannot be employed for all areas. Unless drilling mud and cuttings will be disposed of 

onsite, it is more efficient to use a closed loop tank system to collect this waste and route it to a treatment 

and disposal location, avoiding the impact of constructing a reserve pit and the potential for leakage into 

the environment. 

There are numerous potential drilling mud disposal methods, but the DSGEIS is not clear on what 

method is determined to be best practice for NYS. New Mexico requires all fluids to be removed 

from the reserve pit and recycled or disposed of in accordance with state regulations.20 New Mexico 

also requires the drill cuttings and reserve pit liners be sent to a disposal facility in accordance with 

state regulations, and the soil under the reserve pit to be tested for benzene, total BTEX21, TPH22, the 

GRO23 and DRO24 combined fraction, and chlorides.25 If contamination is found, it must be excavated 

and remediated. If the soil is clean it can be backfilled. The City of Fort Worth, Texas, prohibits 

onsite burial of drilling muds and cuttings.26 The reserve pits are temporary and all muds and cuttings 

must be removed and handled at an approved waste management facility. 

NYSDEC’s consultant, Alpha, concludes that although New Mexico and Texas have more stringent 

drilling cutting and mud disposal standards, allowing onsite burial of drilling cuttings may be acceptable 

for NYS because Pennsylvania allows that approach. Yet there is no analysis of the environmental 

consequences of onsite burial. And, there is no explanation as to why best practices in other states would 

not be considered for NYS. Since drilling muds contain heavy metals and other pollutants, and drill 

cuttings contain NORM in NYS, careful consideration of treatment and disposal options is needed. While 

NYSDEC provides some data on drill cutting NORM content, concluding the NORM content is too low 

to pose a concern. NYSDEC dataset is insufficient to demonstrate that the NORM content will be safe 

statewide, because shales are known to be very heterogeneous and the composition could vary 

substantially. 

Proposed Permit Condition No. 40 requires only that the operator remove and handle drilling fluids 

pursuant to 6 NYCRR § 554.1(c)(1), but drill cuttings containing NORM and coated with drilling mud 

containing heavy metals and other chemicals can remain in the reserve pit after drilling mud is removed. 

Although the requirements of long-term burial are unclear, it appears that NYSDEC is proposing to leave 

the drill cuttings in the reserve pit at the site, without removal or any further treatment.27 

The DSGEIS’s muds and cuttings disposal plan raises a number of concerns. Foremost, 6 NYCRR § 

554.1(c)(1) states that “drilling muds are not considered to be polluting fluids.” Therefore, any waste 

management plan developed to dispose of drilling fluids, and approved by NYSDEC, would be based on 

the assumption that the drilling mud waste was non-toxic. Yet, drilling muds contain heavy metals and 

other pollutants. NYS’s regulations need to be updated to reflect the actual composition of drilling muds 

and the potential environmental risk. NYS’s regulations should provide specific instruction for the proper 

treatment and disposal of drilling muds and cuttings that contain heavy metals and NORM. 

Second, 6 § NYCRR 554.1(c)(1) requires only submission of a waste management plan, but sets no 

standards for disposal. There is no instruction on what to do with the drill cuttings, or whether long-term 

 

20 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.17. 

21 BTEX= benzene, toluene, ethylbenzene, and xylene. 

22 THP= total petroleum hydrocarbons. 

23 GRO= gasoline range organics. 

24 DRO= diesel range organics. 

25 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.17. 

26 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.18. 

27 Except in a flood plain (where reserve pits are prohibited by Permit Condition No. 24).
NYS DSGEIS Page 12 of 39 

onsite burial in the reserve pit is best practice. Alpha confirms that NYS’s oil and gas regulations do not 

include instruction for how to dispose of drill cuttings containing NORM: 

“The State’s Oil and Gas Regulations do not specifically refer to discharge or storage of 

radioactive materials. Low-level, naturally occurring radioactive material (NORM) is present in 

many of the geological formations throughout much of New York. The development of natural gas 

wells into the Marcellus Shale can bring low-level NORM to the surface through produced fluids 

or cuttings. Subpart 380-1.2(e) of 6 NYCRR indicates that Part 380 for the Prevention and 

Control of Environmental Pollution by Radioactive Materials “does not apply to NORM or 

materials containing NORM unless processed and concentrated”; consequently, the disposal of 

drill cuttings from the Marcellus or other gas shales in New York would not be subject to the 6 

NYCRR Part 380 regulations. The drill cuttings generated, therefore, would not fall under 

WRR Section 18-33, and return of the drill cuttings to the ground at a drill pad site within the 

Watershed, also would not be prohibited” [emphasis added]. 28

NYSDEC’s consultant, Alpha, concludes that: 

“Deep well injection and landfill disposal are options in PA, but are not readily available options 

in NY, unless PA has the capacity to handle the increased volume from both NY and PA”29

Therefore, it is not clear what the waste management plan is for drilling fluids and cuttings. Where will 

drilling waste be taken for treatment and disposal? Does the treatment capacity exist to handle this 

incremental waste in NYS? If so, where are the treatment facilities located? What type of treatment will 

be completed? What is the ultimate disposal location for the treatment by-products? If drill cuttings are 

not removed from the reserve pit, how will the operator ensure that there is no contamination left below 

the reserve pit liner before the reserve pit is covered and permanently closed? 

Clearly, there is need for regulatory improvement. The DSGEIS should determine which drilling mud 

composition and disposal practices are “best practice” for the various locations and scenarios under 

evaluation in this DSGEIS. Based on the location and scenario, there may be reason to select one method 

over another. It is critical that NYSDEC carefully think through known best technology methods and best 

management practices, and then explain in the DSGEIS why it has selected the appropriate technology for 

the location and scenario under study. 

At a minimum, the DSGEIS should examine the following practices and make a recommendation for the 

lowest environmental impact: 

1. Waste minimization (drilling mud recycle and reuse when possible); 

2. Use of drilling mud additives with lower environmental impact; 

3. Beneficial reuse of uncontaminated drilling wastes; 

4. Use of closed loop tank systems to transport waste, versus use of reserve pits; 

5. Burial (e.g. landfills, or reserve pits); 

6. Commercial treatment and disposal facilities; and/or 

7. Underground injection. 

A combination of waste minimization, selection of low impact additives, collecting waste in a closed-loop 

system, pumping that waste to a cuttings reinjection (CRI) unit, and disposing of the waste by deep well 

injection into a well-designed, properly constructed disposal well is usually the best management practice 

 

28 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.96. 

29 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p. 20. 
NYS DSGEIS Page 13 of 39 

in most applications. These methods: reduce waste; reduce toxicity; eliminate air pollution; and eliminate 

the need for surface disturbance from reserve pits and the potential for leaks, contamination, and future 

remediation. However, there may be unique locations and situations where this combination of practices 

is not appropriate and that must be thoroughly analyzed by NYSDEC in the DSGEIS. 

4. Disposal of Drilling & Production Waste & Equipment Containing NORM 

Recommendation No. 7: NYSDEC should adopt regulations to establish best practices for 

collection, treatment, and disposal of drilling and production wastes, as well as equipment 

containing NORM. 

The DSGEIS acknowledges that drilling and production waste and equipment may contain Naturally 

Occurring Radioactive Material (NORM). NYSDEC reports that the Marcellus Shale contains Uranium238 and Radium-226, and that this NORM may be present in drill cuttings, produced water and 

stimulation treatment waste.30 NYSDEC identified Radium-226 as the most significant NORM of 

concern, because it is water soluble and has a half-life of 1,600 years.31 Radiation pathways can include 

external gamma radiation, injection, inhalation of particulates, and radon gas.32 

Produced Water Waste: Produced water is rich in chloride, which enhances the solubility of other 

elements, including the radioactive element radium.33 NYSDEC reports it has insufficient data on NORM 

in produced water, but acknowledges that NORM is present and is known to be found in elevated levels. 

NYSDEC identifies the need for additional research and testing.34 The DSGEIS proposed Permit 

Condition No. 47 (Appendix 10) requires produced water to be tested for NORM; yet, no treatment or 

disposal requirements are set based on the NORM testing outcome. It is unclear how the NORM test data 

will be used to establish the best waste management practice to safely dispose of produced water. Buried 

in the DSGEIS at p.7-50 there is one statement that indicates that NYSDEC will use a radioactivity scan 

in the decision to issue a Beneficial Use Determination (BUD), if “potential public exposure concern” is 

indicated, but the threshold for concern is not quantified. Nor is this requirement carried into the proposed 

permit conditions (Appendix 10) or the BUD application (Appendix 12). 

Proposed Permit Condition No. 48 requires only that produced water be “disposed, recycled or reused” 

and transported by a waste transporter with a 6 NYCRR Part 364 permit. No pollutant thresholds, 

disposal limits or treatment requirements are set. 

Recommendation No. 8: NYSDEC should adopt regulations prohibiting use of Marcellus Shale 

gas wastewater containing NORM for land or road spreading applications and establishing best 

practices for collection, treatment and disposal of drilling and production wastes and equipment 

containing NORM. 

Appendix 12 of the DSGEIS states that produced water may be spread on roads if a BUD is issued by the 

NYSDEC Division of Solid and Hazardous Materials, under the Part 364 Transporter Program, but no 

thresholds or standards are established for NORM limits in the material. Other oil and gas producing 

 

30 DSGEIS, p. 4-36. 

31 DSGEIS, p. 6-129. 

32 US Department of Interior, Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil-Field 

Equipment- an Issue for the Energy Industry, USGS Fact Sheet FS-142-99. 33 US Department of Interior, Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil-Field 

Equipment- an Issue for the Energy Industry, USGS Fact Sheet FS-142-99. 34 DSGEIS, p. 5-31.
NYS DSGEIS Page 14 of 39 

states, such as Texas, specifically prohibit road spreading of waste containing NORM.35 A study 

conducted by Argonne National Lab for the US Department of Interior (DOI) concluded that land 

spreading of diluted NORM waste presented the highest potential dose of exposure to the general public 

of all waste disposal methods studied.36 

Since the Beneficial Use Determination does not require an operator to test for NORM,37 it is unclear how 

the NORM testing at the well site will be integrated into the BUD process, and what level of NORM, if 

any will be allowed in fluids used for road spreading. The DSGEIS does not examine the cumulative 

impact of spreading small amounts of NORM, repeatedly over the same area. It is recommended that 

waste containing NORM be prohibited for use in land or road spreading. 

The DSGEIS explores produced water disposal options (e.g. injection wells, treatment plants, and road 

spreading),38 but does not land on a best practice method for produced water containing NORM. 

Produced water containing NORM should not be used for road spreading. Produced water, containing 

NORM, should be returned to the subsurface formation from which it came, or should be handled at an 

approved waste treatment plant. 

Furthermore, EPA identifies produced water pits (brine pits) as an outdated practice if produced water 

contains NORM. EPA reports that: 

“Lined and/or earthen pits were previously used for storing produced water and other 

nonhazardous oil field wastes, hydrocarbon storage brine, or mining wastes. In this case, 

TENORM39 in the water will concentrate in the bottom sludges or residual salts of the ponds. 

Thus the pond sediments pose a potential radiological health risk....produced waters are now 

generally reinjected into deep wells...No added radiological risks appear to be associated with 

this disposal method as long as the radioactive material carried by the produced water is 

returned in the same or lower concentration to the formations from which it was 

derived”40[emphasis added]. 

Hydraulic Fluid Waste: The DSGEIS proposed Permit Condition No. 47 (Appendix 10) requires 

hydraulic fracture (frac) fluid waste to be tested for NORM; yet, no treatment or disposal requirements 

are set based on the NORM testing outcome. It is unclear how the NORM test data will be used to 

establish the best waste management practice to safely dispose of frac fluid. 

Proposed Permit Condition No. 23 requires waste fluids to be handled in accordance with 6 NYCRR § 

554.1(c)(1), yet this regulation does not specify the best practice for handling hydraulic fluid waste. 

Instead, 6 NYCRR § 554.1(c)(1) merely provides a process for an applicant to submit a waste 

management plan. The regulation states: 

 

35 Texas Railroad Commission (TXRRC), 16 Texas Administrative Code, Title 16, Part 1, Chapter 4, Subchapter F, 

§4.601 - 4.632. “Disposal of Oil and Gas NORM Waste”. The TCEQ has jurisdiction over the disposal of other 

NORM wastes. 36 Argonne National Laboratory, Radiological Dose Assessment Related to Management of Naturally Occurring 

Radioactive Materials Generated by the Petroleum Industry, Publication ANL/EAD-2, 1996. 37 The example BUD application provided in Appendix 12 requires testing for calcium, sodium, chloride, 

magnesium, total dissolved solids, pH, iron, barium, lead, sulfate, oil and grease, benzene, ethylbenzene, toluene 

and xylene, but not NORM. 38 DSGEIS, p. 5-131. 

39 TENORM is Technologically Enhanced Natural Occurring Radioactive Material. 

40 http://www.epa.gov/radiation/tenorm/oilandgas.html#disposalpast. 
NYS DSGEIS Page 15 of 39 

“Prior to the issuance of a well-drilling permit for any operation in which the probability exists 

that brine, salt water or other polluting fluids will be produced or obtained during drilling 

operations in sufficient quantities to be deleterious to the surrounding environment, the operator 

must submit and receive approval for a plan for the environmentally safe and proper ultimate 

disposal of such fluids. For purposes of this subdivision, drilling muds are not considered to be 

polluting fluids. Before requesting a plan for disposal of such fluids, the department will take into 

consideration the known geology of the area, the sensitivity of the surrounding environment to the 

polluting fluids and the history of any other drilling operations in the area. Depending on the 

method of disposal chosen by the applicant, a permit for discharge and/or disposal may be 

required by the department in addition to the well-drilling permit. An applicant may also be 

required to submit an acceptable contingency plan, the use of which shall be required if the 

primary plan is unsafe or impracticable at the time of disposal” [emphasis added]. 

Terms such as “sufficient quantities” deleterious to the environment are not quantified. The waste 

disposal method is selected by the applicant, with no instruction on the best waste management practice. 

While recycle and reuse of frac fluid is discussed in the DSGEIS, there is no requirement to use this best 

practice in the proposed permit conditions. There is insufficient information in the DSGEIS to determine 

if the capacity exists to handle the high volumes of frac fluid that may be produced, especially fluid 

containing NORM, through either underground injection or surface treatment and disposal at an 

authorized facility. 

Equipment Scale and Sludge: Equipment (water lines, flow lines, injection wellheads, vapor recovery 

units, water storage tanks, heaters/treaters, and separators)41 used to process natural gas and produced 

water containing NORM can become coated with radium scale and sludge deposits.42 Scale precipitates 

from produced water when it is brought to the surface, cooled to lower temperatures, and subject to lower 

pressures.43 The most common form of scale is barium sulfate, which readily incorporates radium in its 

structure. 

While the DSGEIS acknowledges the likelihood that NORM will build up in equipment scale and 

sludge,44 the proposed permit conditions are silent on how equipment contaminated with NORM should 

be cleaned, handled, and disposed. 

Because E&P waste is exempt from the federal Resource Conservation and Recovery Act (RCRA),45 it is 

critical that states establish clear best practice requirements for handling E&P waste, especially NORM 

found in equipment scale and sludge. The DSGEIS cites other oil and gas states, such as Texas and 

Louisiana, as adopting stringent NORM regulations, including: occupational dose control, surveys, testing 

and monitoring, record keeping, signs and labeling, and treatment and disposal methods.46 Yet, the 

DSGEIS does not recommend adopting these more stringent approaches taken by other states and is silent 

on any recommendation in the proposed permit conditions (Appendix 10). 

 

41 Argonne National Laboratory, Radiological Dose Assessment Related to Management of Naturally Occurring 

Radioactive Materials Generated by the Petroleum Industry, Publication ANL/EAD-2, 1996. 42 US Department of Interior, Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil-Field 

Equipment- an Issue for the Energy Industry, USGS Fact Sheet FS-142-99. 43 US Department of Interior, Naturally Occurring Radioactive Materials (NORM) in Produced Water and Oil-Field 

Equipment- an Issue for the Energy Industry, USGS Fact Sheet FS-142-99. 44 DSGEIS, p. 6-30. 

45 Environmental Protection Agency, Exemption of Oil and Gas Exploration and Production Wastes from Federal 

Hazardous Waste Regulations, EPA530-K-01-004, October 2002. 46 DSGEIS, p. 7-101.
NYS DSGEIS Page 16 of 39 

The DSGEIS (Section 7.8.2)47 describes NYS’s existing radioactive waste regulations, noting that 

equipment contaminated with NORM may be subject to the NYS Department of Health licensing 

requirements under State Sanitary Code, Chapter 1, Part 16 (10 NYCRR 16) and Industrial Code Rule 38 

(12 NYCRR 38). Yet it makes no conclusion as to whether E&P equipment contaminated with NORM 

will actually be subject to regulation or how the waste will be collected, treated, and disposed. 

While NYS has some current regulations relating to radioactive material exposure and disposal, these 

rules are not specific to gas production equipment or methods. NYSDEC should adopt regulations to 

establish best practices for collection, treatment, and disposal of drilling and production wastes and 

equipment containing NORM. 

NYSDEC should evaluate the following list of practices and determine which are best for the specific 

locations and scenarios examined in the DSGEIS: 

1. NORM testing of all material produced from the gas well, all material used in well stimulation 

and equipment scale and sludge; 

2. NORM testing of equipment scrap metal, and cleaning prior to smelting. Pollution control 

devices (e.g. filters and bubblers) should be installed in smelter stacks to reduce airborne 

radiation; 

3. Reinjection of produced water back into aquifer of the gas reservoir from which it came; 

4. Treatment and disposal by a licensed NORM disposal facility; or 

5. Collection and transportation of waste for disposal in a salt dome. 

5. Casing and Cementing Requirements 

Recommendation No. 9: NYS casing and cementing regulations should be developed specific to 

Marcellus Shale gas reservoir development. They should address high angle well construction, 

ensuring that casing and cementing are structurally sound and provide an effective drinking water 

barrier, particularly when high-volume fracture treatments are performed. 

Section 2.4.6 concludes that drinking water well contamination by oil and gas drilling activities, such as 

incidents reported in the 1980s in Chautauqua County, is mitigated by NYS’s new casing and cementing 

practices and fresh water aquifer supplementary permit conditions. 

While NYS’s new casing and cementing practices are an improvement, these requirements are found in 

guidance instead of regulation, and therefore are subject to change by appointed officials without public 

review. The DSGEIS should conclude that NYS’s new casing and cementing practices and fresh water 

aquifer supplementary permit conditions are mandatory minimum requirements for all wells drilled and 

fractured in low-permeability gas reservoirs in the state. Additionally, NYSDEC should take steps to 

codify these requirements in regulation. 

Attachment C to the Comments on this DSGEIS prepared by AKRF, Inc. provides a September 16, 2009 

report to NRDC documenting several recommendations for improving NYS’s best practices for casing 

and cementing.48 The September 16, 2009 report compares NYS’s best practices for casing and cementing 

to those of other large and experienced oil and gas producing states (Texas, California, Alaska and 

Pennsylvania). Specific recommendations are included for: high angle well casing and cementing; cement 

 

47 DSGEIS, p. 7-103. 

48 New York State (NYS) Casing Regulation Recommendations, report prepared by Harvey Consulting, LLC., for 

the Natural Resources Defense Council (NRDC), September 16, 2009. 
NYS DSGEIS Page 17 of 39 

and casing quality standards and testing; operator certification; and when to set intermediate casing to 

protect ground water (especially in wells that undergo fracture treatments). 

6. Flaring, Venting, and Fugitive Emissions 

Recommendation No. 10: NYSDEC should develop regulations to restrict flaring, venting, and 

fugitive emissions to the lowest level technically feasible. 

Both federal and state governments have taken steps over the past two decades to enact regulations that 

limit flaring and venting of natural gas.49 Initially the motive was to conserve hydrocarbon resources to 

maximize federal and state revenue and gas supply. More recently, focus on greenhouse gas (GHG) 

emission reduction has prompted additional innovation to further reduce flaring and venting. 

Reducing flaring and venting to the lowest level technically achievable is widely considered best practice. 

The proposed permit conditions do not include this best practice. Proposed Permit Condition No. 2 

merely requires notification to the county emergency management office when flaring occurs. NYSDEC 

should develop regulations to restrict flaring, venting, and fugitive emissions to the lowest level 

technically feasible. 

Drilling & Completions: Flares may be used during well drilling, completion and testing to safely 

combust hydrocarbon gases that cannot be collected because gas processing and pipeline systems have 

not been installed. If gas processing equipment and pipeline systems are in place, gas flaring can be 

avoided in all cases except equipment malfunction. 

During the drilling and completion phase of the first well on a well pad, a gas pipeline may not be 

installed. Gas pipelines are typically not installed until it is confirmed that an economic gas supply is 

found. Therefore, gas from the first well is often flared or vented during drilling and completion activities 

because there is not a pipeline to route it to. However, subsequent wells drilled on that same pad would be 

in a position to implement Reduced Emission Completion (REC), also called “green completion,” which 

involves routing gas to a pipeline. Green completions require equipment to be brought to the well site to 

process wet gas from the well (during well completion activities) to ensure the gas meets pipeline 

specifications. The DSGEIS states that green completions are not currently required in NYS.50 The 

DSGEIS estimates that without a gathering line in place, initial cleanup or testing could require flaring to 

last for three to 30 days.51

Gas Production: High pressure gas buildup may require gas venting via a pressure release valve, or gas 

may need to be routed to a flare during an equipment malfunction. At natural gas facilities, continuous 

flaring or venting may be associated with the disposal of waste streams52 and gaseous by-product 

streams53 that are uneconomical to conserve.54 Venting or flaring may also occur during manual or 

 

49 Global Gas Flaring Reduction Partnership (GGFR), Guidance on Upstream Flaring and Venting Policy and 

Regulation, Washington D.C., March 2009. 50 DSGEIS, p. 6-52. 

51 DSGEIS, p. 5-125. 

52 For example, acid gas from the gas sweetening process and still-column overheads from glycol dehydrators. 53 For example: instrument vent gas; stabilizer overheads and process flash gas. 

54 The Global Gas Flaring Reduction partnership (GGFR) and the World Bank, Guidelines on Flare and Vent 

Measurement, September 2008. 
NYS DSGEIS Page 18 of 39 

instrumented depressurization events, compressor engine starts, equipment maintenance and inspection, 

pipeline tie-ins, pigging, sampling activities, and removal of hydrates from pipelines.55

Best practices for flaring and venting during gas production should limit flaring and venting to the 

smallest amount needed for safety. Gas should be collected for sale, used as fuel, or reinjected for 

pressure maintenance, unless it is proven to be technically and economically unfeasible. 

NYSDEC should adopt very clear regulations limiting flaring and venting during gas production 

operations. If gas collection, use, or sale is not possible, NYSDEC should require operators to flare gas as 

a preferred method over venting. Gas flaring is environmentally preferable over venting because flaring 

reduces hazardous air pollutants, volatile organic compound emissions, and GHG emissions.56 

Several states (e.g. Alaska and California) require operators to keep accurate records of gas venting and 

flaring to ensure that the amount is limited to safety related needs. Some states and the federal 

government (in the Outer Continental Shelf) require operators to pay royalty and taxes on flared and 

vented gas not authorized for safety purposes. This encourages investment in gas collection and control 

devices to conserve natural gas. 57

Best Practices for Flares: When flare use is necessary for safety, the following best practices should be 

instituted: 

• Minimize the risk of flare pilot blowout by installing a reliable flare system; 

• Ensure sufficient exit velocity or provide wind guards for low/intermittent velocity flare streams; 

• Ensure use of a reliable ignition system; 

• Minimize liquid carry over and entrainment in the gas flare stream by ensuring a suitable liquid 

separation system is in place; and 

• Maximize combustion efficiency by proper control and optimization of flare fuel/air/steam flow 

rates. 

Best Practices for Venting and Fugitive Emissions: Best Practices for controlling venting and fugitive 

emissions include: 

• Leak Detection and Repair (LDAR) programs including acoustic detectors and infrared 

technology to detect odorless and colorless leaks; 

• Use of low bleed pneumatic instruments,58 instrument air, electric or solar powered control 

devices; 

• Use of dry centrifugal compressor seals; 

• Use of smart automation plunger lifts for liquid unloading; 

• Early installation of pipelines; and 

• REC methods for gas well completions. 

In most cases these best practices improve safety and collect marketable gas for sale. For example, RECs, 

“green completions,” provide an immediate revenue stream by routing gas that would otherwise be vented 

 

55 The Global Gas Flaring Reduction partnership (GGFR) and the World Bank, Guidelines on Flare and Vent 

Measurement, September 2008. 56 Fugitive and Vented methane has 21 times the global warming potential as combusted methane gas. 

Methanetomarkets.org, epa.gov/gasstar. 57 Global Gas Flaring Reduction Partnership (GGFR), Guidance on Upstream Flaring and Venting Policy and 

Regulation, Washington D.C., March 2009. 58 Process controllers, chemical pumps, and glycol pumps often vent pressurized natural gas used for pneumatic 

actuation. 
NYS DSGEIS Page 19 of 39 

to a gas sale line. Industry has demonstrated that green completions are both best environmental practice 

and profitable. Green completion equipment has a short economic payout. A green completion requires 

the operator to bring in gas processing equipment to the well pad to clean up wet gas, improving it to gas 

pipeline quality. Typically, portable gas dehydration units, gas-liquid-sand separator traps, and additional 

tanks are required.59 Most companies report a one-to-two-year payout for investment in their own green 

completion equipment, and substantial profit thereafter, depending on the gas flow rate.60 It is also 

possible for smaller operators to rent green completion equipment. NYSDEC’s consultant, ICF 

Incorporated LLC, found that equipment payouts may be as short as three months, and more than $65 

million in profits was made on a national level in 2005 by companies conducting green completions.61 

Natural Gas STAR also provided technical advice to NYSDEC (Appendix 23) recommending green 

completions as a technically feasible economic method. Yet, the DSGEIS does not require green 

completions. The DSGEIS encourages participation in the Natural Gas STAR program,62 but this program 

is voluntary and will not require operators to institute flaring and venting reductions. The best practice of 

green completions should be codified in NYS regulation. 

7. Hydrogen Sulfide 

Recommendation No. 11: NYSDEC should adopt regulations to require gas production 

operators to follow hydrogen sulfide detection and protection procedures for employees and the 

public during drilling and production operations. 

The DSGEIS proposed Permit Condition No. 21 requires operators to conform to the American Petroleum 

Institute Recommended Practice 49 (API RP49) for Drilling and Well Servicing Operations Involving 

Hydrogen Sulfide. Hydrogen sulfide (H2S) is a deadly gas. API RP49 is widely accepted as a guidance 

document. However, API RP49 does not address H2S at gas production and processing facilities. API RP 

55 addresses Oil and Gas Producing and Gas Processing Plant Operations Involving Hydrogen Sulfide, 

including procedures to protect employees and the public. Both API RP49 and API RP55 should be added 

to NYS’s regulatory requirements. 

8. Seismic Data Collection 

Recommendation No. 12: NYSDEC should establish regulatory requirements for seismic data 

collection that reduce impact to the environment and the public. 

The DSGEIS addresses naturally occurring seismic events in Chapter 4, but is silent on the impacts of 

industrial seismic exploration used to locate subsurface gas reservoirs. Seismic waves created from a 

source on the surface travel through the earth and are reflected back to surface. Recording instruments 

called geophones collect data and transmit it to a seismic recording truck. The speed at which waves 

travel through the earth and are reflected allow geophysicists to map subsurface geology and identify 

potential gas reservoirs. 

 

59 EPA, Green Completion, Partner Reported Opportunities (PROs) for Reducing Methane Emissions, Fact Sheet 

No. 703, 2004. 60 Reduced Emissions Completions, Lessons Learned from Natural Gas STAR, Producers Technology Transfer 

Workshop, Casper Wyoming, August 30, 2005. 61 DSGEIS, Appendix 25. 

62 DSGEIS, p. 7-92. 
NYS DSGEIS Page 20 of 39 

Historically seismic exploration was most commonly conducted using dynamite placed in surface drilled 

boreholes to create small surface explosions that produced the requisite seismic waves.63 Due to 

environmental and public concerns, dynamite use has decreased, and has commonly been replaced by 

large, heavy wheeled or tracked vehicles with Vibroseis units that propagate energy signals into the earth, 

or “thumper” trucks that pound the ground surface to create seismic vibrations by dropping a heavy 

weight raised by a hoist. 

Seismic exploration data can be obtained to create two and three dimensional subsurface maps. This data 

is collected by running seismic equipment along a tightly gridded surface path, often requiring trees and 

brush to be cut to allow passage of the heavy equipment and crews. This method leaves surface scarring. 

Due to competition among operators to locate gas resources, seismic surveys are usually collected and 

held proprietary, requiring each operator to collect its own data. This leads to multiple seismic surveys 

over the same surface terrain. 

Best practices for seismic exploration should include: 

• Prohibiting explosive use and requiring less destructive methods such as Vibroseis; 

• Acquiring data during winter months, when ground is frozen and surface impacts are minimized; 

• Encouraging operators to jointly conduct seismic surveys whenever possible to avoid repeat 

impacts; 

• Limiting equipment and crew sizes to the smallest units possible to minimize surface damage and 

reduce the amount of tree and vegetation removal required; 

• Maximizing data acquisition along existing roadways and cleared utility easements and routes; and 

• Requiring restoration (planting trees and vegetation). 

These best practices should be codified in NYS regulation. 

9. Corrosion & Erosion Control 

Recommendation No. 13: NYS regulations should require equipment to be designed to prevent 

corrosion and erosion, and require monitoring, repair, and replacement programs. 

Downhole tubing and casing, surface pipelines, pressure vessels, and storage tanks used in oil and gas 

exploration and production are subject to internal corrosion by water, enhanced by the carbon dioxide 

(CO2) and hydrogen sulfide (H2S) present in the gas. High velocity gas contaminated with water and 

sediment can erode internal pipes, fittings and valves. 

The DGEIS includes a discussion on corrosion inhibitors used by industry in fracture treatments, but does 

not require the best practice to design facilities resist to corrosion (e.g. material selection and coatings), or 

to monitor corrosion and repair and replace corroded equipment.64 The DSGEIS concluded that NYS 

regulations need to be revised to require erosion monitoring, repair, and replacement programs as best 

practice. 

 

63 Sheriff, Robert E. and Lloyd P. Geldart, Exploration Seismology, Cambridge University Press, Cambridge., 1995. 

64 Curran, E., Corrosion Control in Gas Pipelines, Coating Protection Provides a Lifetime of Prevention, Pipeline & 

Gas Journal, October 2007. 
NYS DSGEIS Page 21 of 39 

10. Spill Prevention 

Recommendation No. 14: NYSDEC should adopt regulations to require more stringent oil spill 

prevention measures for temporary fuel tanks associated with drilling and well stimulation 

activities. NYSDEC should incorporate existing EPA oil spill prevention standards for oil and gas 

activities that require secondary containment for all fuel tanks 1,320 gallons and larger. 

Section 5.2.1 and Appendix 7 include sample rig specifications showing 10,000-12,000-gallon fuel 

storage tanks used with the large rigs. Section 7.1.3.1 states the drilling rig fuel tanks are exempt from 

NYS’s petroleum bulk storage regulations, and tank registration requirements at 6 NYCRR §§ 612-614, 

because they are temporary storage tanks (non-stationary). 

It is not clear why temporary fuel tanks are exempt from NYS’s spill prevention regulations, when all 

other tanks 1,100 gallons and larger must register in NYS, install secondary containment, and undergo 

inspections at 5 and 10 year intervals. A temporary 1,100 gallon fuel tank poses a greater environmental 

risk than a stationary 1,100 gallon fuel tank, because temporary fuel tanks are relocated many times 

during their operating lives, increasing the potential for tank damage during transit. Large temporary fuel 

tanks should be subject to the same secondary containment requirements as large stationary fuel tanks, 

particularly when they may be installed in one location for a significant period of time, or alternative 

methods such as use of double walled or vaulted tanks should be considered, as explained further below. 

NYSDEC recommends two mitigation measures be added to prevent fuel spills: 

(1) “encouragement” to operators to set the tank 500’ back from water bodies; and 

(2) requirement to install secondary containment for tanks 10,000 gallons and larger placed within 500’ 

of a waterbody. 

NYSDEC references a draft NYSDEC Program Policy DER-17 for construction standards and a 

September 28, 1994 Spill Prevention Operations Technology Series (SPOTS) memo for guidance on how 

the secondary containment might be constructed. Appendix 10 proposed Permit Condition No. 13 relies 

on the outdated SPOTS memo and establishes weak setback standards “to the extent practical.” 

The DSGEIS does not cite existing EPA spill prevention requirements at 40 CFR § 112 that apply to fuel 

tanks, including drilling tanks at 40 CFR § 112.7(c). EPA’s regulations, which were revised in 2002, 

require sufficiently impervious secondary containment to prevent a discharge to the environment for tanks 

1,320 gallons and larger. EPA allows an operator the opportunity to demonstrate under 40 CFR § 

112.7(d) that it is impracticable to install secondary containment; however, EPA requires a formal written 

“impracticability determination.” It also requires periodic integrity testing of the tank, leak testing of the 

valves and associated piping, a Part 109 contingency plan, and a written commitment of manpower, 

equipment, and materials to respond to a spill. 

NYSDEC’s recommended mitigation measures, and proposed Permit Condition No. 13, are insufficient to 

protect the environment from fuel spills. 

• First, NYSDEC’s proposed mitigation measure to “encourage” operators to set the tank 500’ back 

from water bodies65 is not enforceable. 

• Second, NYSDEC’s proposed mitigation measure to require secondary containment for tanks 10,000 

gallons and larger placed within 500’ of a waterbody provides less spill protection than EPA’s 

standard. 

 

65 DGEIS, p. 7-27. 
NYS DSGEIS Page 22 of 39 

• Third, NYSDEC proposed mitigation measures reference an unenforceable draft NYSDEC Program 

Policy document (DER-17) for construction standards and an outdated September 28, 1994 Spill 

Prevention Operations Technology Series (SPOTS) memo for guidance on how a secondary 

containment could be constructed. 

The DSGEIS estimates that as many as 16 vertical wells (9 horizontal) could be drilled from one central 

pad; each well would take approximately one month to drill; and approximately 10 wells could be 

completed and hooked up for production within a year.66 Therefore large fuel tanks used for drilling could 

be located at a drill site for 1.5 years. This is sufficient time to install secondary containment for tanks. 

When fuel tanks are used for shorter periods of time (e.g., a single well), double-walled or self-diking 

tanks could be used, avoiding the need to construct a large temporary containment are for only a short 

duration. 

NYS regulations (either at 6 NYCRR §§ 612-614 or in 6 NYCRR §§ 550-559 pursuant to its authority 

under Environmental Conservation Law § 23-0305(8)(d)) should be amended to include drilling 

operations. Secondary containment standards, as well as inspection and integrity standards at 6 NYCRR 

§§ 613-614, should be applied to all fuel tanks of at least 1,100 gallons used to explore or develop the 

Marcellus Shale gas reservoir (and any other gas reservoir covered under the final EIS). 

Other oil and gas producing states have allowed the use of vaulted, self-diked, or double-walled portable 

tanks to meet the secondary containment requirement in cases where the operator can demonstrate it is 

infeasible to install a containment area meeting EPA’s 110% of the largest tank volume requirement. 

NYSDEC could consider allowing these alternative tanks where secondary containment is proven to be 

infeasible. 

Vaulted, self-diked, and double-walled portable tanks are equipped with catchments that hold fuel 

overflow or divert it into an integral secondary containment area. Industry standards for construction of 

vaulted, self-diked, and double-walled portable tanks include: 

• Underwriters Laboratories' Steel Aboveground Tanks for Flammable and Combustible Liquids (UL 

142); 

• Appendix J of the American Petroleum Institute's (API) Welded Steel Tanks for Oil Storage (API 

650); and, 

• API’s Specification for Shop Welded Tanks for Storage of Production Liquids (API Spec 12F). 

Due to higher potential for damage during relocation and use at multiple sites, it is recommended that 

inspections be routinely performed on vaulted, self–diked, and double-walled portable tanks to identify 

damage or corrosion using one of the following standards: 

• Steel Tank Institute's (STI) Standard for the Inspection of Aboveground Storage Tanks, Third 

Edition (STI SP00l); or 

• API’s Tank Inspection, Repair, Alteration, and Reconstruction Standard (API 653). 

Additionally, most oil-producing states also require that stationary and portable tanks be equipped with 

high–liquid-level alarms that sound and display in a manner immediately recognizable to personnel 

 

66 DSGEIS at pgs. 117, 120, and 311. 
NYS DSGEIS Page 23 of 39 

conducting a transfer; high–liquid-level automatic pump shutoff devices set to stop flow at a 

predetermined tank content level; and a means of immediately determining the liquid level of each tank. 

11. Spill Response 

Recommendation No. 15: NYSDEC should adopt EPA SPCC requirements for drilling 

operations. 

The DSGEIS at p. 7-33 recommends a spill response team and employee training for spill prevention. 

EPA’s regulations at 40 CFR § 112 require a Spill Prevention Control and Countermeasures (SPCC) Plan 

for fuel storage volumes of 1,320 gallons or greater. EPA’s requirements are much more comprehensive 

and stringent than the proposed mitigation measures suggested by NYSDEC. The DSGEIS should clearly 

state EPA’s SPCC requirements, so that all operators are aware of them and comply. NYSDEC may also 

want to adopt more stringent oil spill prevention and response requirements in its regulations that exceed 

the federal EPA standard (many states have taken this approach). 

12. Fuel Selection 

Recommendation No. 16: NYSDEC should require operators to use cleaner fuels than diesel 

(such as natural gas) or electric power whenever technically feasible. 

Shale gas development provides a cleaner natural gas fuel source than liquid fuels. The DSGEIS is based 

on use of large quantities of diesel fuel to power onsite equipment, without consideration of alternative 

cleaner energy sources. While diesel engines are often used as the prime mover power supply for rotary 

well drilling, natural gas or dual fuel (diesel/gas) engines are available to take advantage of cleaner fuel 

supplies.67 EnCana, a gas producer, reports natural gas fired rigs reduce air pollution by 90% compared to 

diesel fired rigs.68 

Some rigs have been converted to accept electric power. Power can also be supplied to the drilling rig by 

a natural gas powered reciprocating turbine that can generate electricity on site. If high-line power is 

available nearby the well site, rig power can be obtained directly from power lines, substantially reducing 

local air pollution impacts. Natural gas fired and electric powered rigs are commonly used in Alaska to 

reduce air pollution. 

Power generated by natural gas fired engines or turbines can be used for hoisting equipment, fluid 

circulating equipment, lighting, rotary equipment, and to meet gas compression requirements. 

An initial well on a well pad needs to be drilled with diesel to obtain a natural gas supply; subsequent 

wells can be drilled using natural gas or electric power. Smaller temporary gas processing units are 

available to process wellhead gas to the quality required for equipment use. 

 

67 www.naturalgas.org. 

68 EnCana 2005 Annual Report.
NYS DSGEIS Page 24 of 39 

13. Hydraulic Fracture Design and Monitoring 

Recommendation No. 17: NYSDEC should revise its regulations to specify best technology and 

best practices that must be used to collect data, model, design, implement, and monitor a fracture 

treatment. The regulations should specify that all data collected by industry must be reported to 

NYSDEC and made available to the public. Best technology and best practices should include: 

(a) Collecting additional geophysical and reservoir data to support a reservoir simulation model; 

(b) Developing a high-quality Marcellus Shale 3D reservoir model(s) to safely design fracture 

treatments; 

(c) Hydraulic fracture modeling prior to each fracture treatment to ensure that the fracture is 

contained to the Marcellus Shale zone; 

(d) Careful monitoring of the fracture treatment, including shutting the treatment down if data 

indicates casing leaks or out-of zone fractures; 

(e) Collecting data, and carefully analyzing fracture treatment performance in the field on 

smaller fracture treatments in the deepest, thickest sections of the Marcellus Shale to gain 

data and experience (e.g. at least 4,000’ deep and 150’ thick); 

(f) Using experience gained on fracture testing in (e) to design and implement larger treatment 

volumes over time (potentially allowing increasingly shallower and thinner intervals, only if 

technical data supports the safety of this technique); 

(g) Documenting, reporting, and remediating fracture treatment failures to ensure drinking water 

protection; and 

(h) Taking a conservative, step-wise approach to ensure there is technical data to support highvolume fracture treatments that protect the environment, before NYSDEC establishes a 

blanket permitting program allowing fracturing of the Marcellus Shale at all depths and all 

thickness intervals. 

 

Experts agree that Marcellus Shale gas production can be maximized by drilling long horizontal wells to 

increase the drainage area, and conducting hydraulic fracture treatments to improve permeability and 

access to trapped gas. However, successful, safe development requires hydraulic fracture treatments that 

are properly designed and sized to create fractured rock and improved permeability within the shale zone. 

Fracture treatments that propagate fractures outside the shale zone (fracturing out-of-zone) reduce gas 

recovery and may risk pollutant transport beyond the Marcellus Shale formation. Pollutant transport and 

pollutant toxicity issues are addressed in Tom Myers’ and Glenn Miller’s reports to NRDC on the 

DSGEIS, and therefore are not addressed here. This recommendation centers on what type of data, 

analysis, tools, and methods a professional engineer/operator should have in place and use to ensure that a 

fracture treatment can be contained within the Marcellus Shale zone. 

The DSGEIS does not demonstrate that NYSDEC and/or operators have sufficient data on the NYS 

Marcellus Shale. Nor does it demonstrate that engineering tools are in place to ensure high-volume 

fractures can be constrained to the Marcellus Shale. 

Buffer Zones Needed: Vertical fractures that extend above and below the shale zone will decrease gas 

recovery rates by allowing vertical migration into the overlying strata, or by allowing water influx from 
NYS DSGEIS Page 25 of 39 

aquifers above or below the shale. NYS has a financial incentive to ensure fracture treatments are 

conducted correctly, because NYS will want to maximize its royalty share and tax revenue. 

To avoid fracturing out-of-zone, engineers typically design fracture treatments with a buffer zone (an unfractured zone at the top of the shale layer and at the base of the shale). Buffer zone size should increase 

with geologic and technical uncertainty. Buffer zone size may decrease as industry gains experience and 

data quality/quantity improves. The DSGEIS does not contain sufficient information to demonstrate that 

NYSDEC and/or operators proposing high-volume fracture treatments have developed engineering tools 

capable of computing a safe buffer zone. 

Marcellus Experience Very Limited: Marcellus Shale gas development has a high level of uncertainty. 

Shales by nature are very heterogeneous.69 Industry has limited experience exploiting the Marcellus Shale 

using horizontal wells and slickwater fracs. The first Appalachian Basin Marcellus Shale gas well 

stimulation using high-volume slickwater fracture treatments was only recently performed in 

Southwestern Pennsylvania in 2004.70 Therefore, industry has less than five years of experience 

developing the Marcellus Shale using the techniques proposed in the DSGEIS. 

Even NYSDEC’s consultants acknowledge that industry literature on and experience with the Marcellus 

Shale is so limited that most of their analysis was based on development of other shale gas reservoirs, 

such as the Barnett and Fayetteville. NYSDEC’s consultant, ICF, states that: 

“Drilling operations, and especially multi-horizontal wells, are relatively new in Marcellus 

Shale. While drilling operations are underway in neighboring states as evidenced by over 450 

wells in Pennsylvania for example, technical studies have yet to be published that quantify actual 

drilling operations in Marcellus Shale. For the most part, we have had to make assumptions, 

where technically appropriate, that drilling operations in other shale formations are 

representative of expected Marcellus operations [emphasis added].71

Lack of Marcellus Shale experience increases the risk of fracturing out-of-zone, unless a conservative, 

step-wise approach is taken to better understand the Marcellus Shale before large scale development 

occurs in NYS. 

NYS Marcellus Data Set Improvement Needed: Site-specific data, unique to the Marcellus Shale in 

NYS, must be collected to: better understand the reservoir heterogeneities; develop sophisticated three 

dimensional (3D) reservoir models to more accurately design fracture treatments; and examine actual 

fracture performance in the field. Reservoir simulation models are critical engineering design tools. The 

DSGEIS provides no indication that a model exists for the NYS Marcellus Shale. 

Engineers use 3D models to predict fracture height, length, and orientation prior to actually performing 

the job at the well. The goal is to design a stimulation treatment that optimizes fracture networking and 

maximizes gas production, while confining fracture growth to within the gas shale target formation.72 

 

69 Cipolla, C.L., Lolon, E.P., and Mayerhofer, M.J., Reservoir Modeling and Production Evaluation in Shale-Gas 

Reservoirs, International Petroleum Technology Conference, Paper 13185, December 2009. 70 Fontaine, J., Johnson, N., and Schoen, D., Design, Execution, and Evaluation of a “Typical” Marcellus Shale 

Slickwater Stimulation: A Case History, Society of Petroleum Engineers Paper 117772, October 2008. 71 NYS DSGEIS, ICF Task 2 Report, p.1. 

72 ALL Consulting, Hydraulic Fracturing Considerations for Natural Gas Wells of the Marcellus Shale, Presented at 

The Ground Water Protection Council 2008 Annual Forum Cincinnati, Ohio, September 21-24, 2008. 
NYS DSGEIS Page 26 of 39 

Engineers examine various parameters (e.g., volume, pressure, treatment placement) to optimize a 

fracture treatment. Without a high-quality 3D reservoir simulation model to design a fracture treatment, 

operators cannot demonstrate to NYSDEC that the fracture is predicted to stay in zone. 

Typically an operator would start by collecting core analysis, well logs, and other subsurface data in the 

area it is interested in developing, to populate a site-specific 3D reservoir model. To collect this data, 

additional exploration and appraisal wells must be drilled (see recommendation No. 2). The limited 

amount of special core analysis and core data on the Marcellus Shale, as well as overlying intervals, is 

described in Chapter 4 of the DSGEIS, showing a need for additional data. 

Test in Deepest, Thickest Zones First: NYSDEC is proposing to allow high-volume fracture treatments, 

without requiring the standard of care a petroleum engineer would typically use to collect data, and 

model, design, and monitor fracture treatments. NYSDEC should require that additional data be collected 

to support a model, and initially it should only allow a few, small fracture treatments that are conducted 

with intensive monitoring to verify that they are designed and implemented to stay within the Marcellus 

Shale. This data gathering and testing should be conducted in the deepest portions of the Marcellus Shale 

(below 4,000’) and in the thickest section of the shale (over 150’) to ensure there are adequate buffer 

zones to protect the environment during the data gathering and testing process. Operators should start 

with smaller fracture treatment sizes, collecting field data to better understand fracture performance, and 

use field data to calibrate that performance in the 3D model. 

Over time, with careful analysis and a conservative, step-wise approach, larger fracture treatments can be 

tested and carefully monitored. Over time it may be possible to safely use the treatments on thinner 

reservoirs and shallower reservoirs, but certainly not as a first step. High-volume fracture treatments 

should not be conducted until there is a sophisticated data set, model, and monitoring program to verify 

pre-fracture and post-fracture reservoir properties. 

Regulations Needed: While NYSDEC’s consultant, ICF73, documents a number of the engineering 

methods that can be used to model, monitor, and improve fracture treatments, NYSDEC does not require 

any of these methods in its existing regulations. Absent a regulatory requirement, there is no assurance 

these methods will be used. 

Best practice for hydraulic fracture planning includes a detailed understanding of the in-situ conditions 

present in the reservoir (e.g., shale thickness, reservoir pressure, rock fracture characteristics, and special 

core analysis). In highly heterogeneous reservoirs, reservoir simulation is often coupled with stochastic 

methods (e.g. Monte Carlo analysis and geostatistical techniques) to improve the quality of the 3D 

reservoir model.74 

Data collected on previous fracture treatments in the Marcellus Shale and drilling data will be useful to 

refine the fracture modeling. Actual fracture treatments must be carefully monitored and implemented to 

ensure fractures stay within zone. Data collected during each fracture treatment should be used to 

calibrate the 3D reservoir model to improve future fracture treatment design. 

Peer-reviewed articles and technical data on Marcellus Shale vertical fracture growth characteristics are 

sparse. While fracture growth models exist at an industry level, and have been tuned for fracture 

treatments in the Barnett Shales and other gas reservoirs, considerable technical work is still needed to 

develop fracture growth models for NYS Marcellus Shale development. 

 

73 ICF International, Technical Assistance to NYS on DSGEIS, August 2009. 74 Schepers, K.C., Gonzalez, R.J., Koperna, G.J., and Oudinot, A.Y., Reservoir Modeling in Support of Shale Gas 

Exploration, Society of Petroleum Engineers, June 2009. 
NYS DSGEIS Page 27 of 39 

A literature review was completed by the author in search of a Marcellus Shale 3D reservoir model for 

NYS; none was found in the petroleum engineering published literature. It is not clear if the lack of a 

Marcellus Shale reservoir model for NYS indicates that one does not exist, or whether industry is holding 

models proprietary. Yet in other shale gas developments (e.g., Barnett and Fayetteville) there is extensive 

industry literature on: available reservoir simulation model; completion and fracture design; and 

performance assessment to compare predicted fracture growth with that achieved in the field. Lack of 

industry literature is usually a strong indication that additional data gathering and technology 

development is needed. 

The data void for NYS’s Marcellus Shale technical literature reinforces the need for NYSDEC to use a 

conservative, step-wise approach, rather than launching into a massive drilling and fracturing campaign 

without the data or tools in place to do a safe and effective job. 

NYSDEC should require additional information be collected by industry to better understand the 

geological and geophysical properties of the Marcellus Shale zone and the overlying strata between the 

Marcellus and drinking water aquifers. 

NYSDEC should require 3D reservoir simulation models be developed to accurately predict hydraulic 

fracture treatment performance, and to ensure the jobs are well engineered and designed with adequate 

safety factors to avoid fracturing out-of-zone. 

The DSGEIS must assure the public that fractures can be contained to the Marcellus Shale zone. The 

DSGEIS does not provide data sufficient to meet this standard. The DSGEIS does not document the 

existence of 3D reservoir simulation models for NYS’s Marcellus Shale, nor does NYSDEC require 

engineers to design fracture treatments using 3D models. 

While Marcellus Shale development in Pennsylvania precedes development in NYS, data collected from 

the Pennsylvania wells is not applicable to the NYS Marcellus Shale because the depth of burial, 

thickness, organic content, permeability, and other reservoir properties in NYS differ. Industry experts 

warn that site-specific data is critical: 

“By their nature, shales are extremely variable and regional differences in structure, 

mineralogy and other characteristics should always be considered in treatment design...The 

wide geographic range [of the Marcellus Shale] has led to numerous different completion 

schemes being utilized as with the geographic variation comes geologic variability within the 

formation itself. A primary topic of [industry] discussion has been determining the optimal size 

and type of stimulation treatment for a given area” 75 [emphasis added]. 

The Marcellus Shale thickness drops off substantially in western NYS to less than 75’ for roughly onethird of the total development.76 Fracturing thin shale zones increases the risk of fracturing out-of-zone, 

unless a very cautious approach is taken to design and implement the fracture treatment. Hydraulic 

fracture treatments in NYS must be carefully tailored to the geophysical properties of the Marcellus Shale 

in NYS, taking into account shale thickness, local stress conditions, compressibility, and rigidity. 

NYSDEC’s consultants point out that a gas operator has no incentive to fracture out of the Marcellus 

Shale zone because doing so could result in a loss of gas reserves or increase produced water volumes. 

 

75 Fontaine, J., Johnson, N., and Schoen, D., Design, Execution, and Evaluation of a “Typical” Marcellus Shale 

Slickwater Stimulation: A Case History, Society of Petroleum Engineers Paper 117772, October 2008. 76 DSGEIS, Figure 4.9. 
NYS DSGEIS Page 28 of 39 

Yet NYSDEC’s consultant, ICF, also recognizes that fracture design is complicated and it could be 

possible to inadvertently fracture out of zone. As a result, ICF examined the potential for fracture fluids to 

propagate vertically and contaminate an overlying drinking water aquifer. 

Proposed permit conditions (Appendix 10) require a Pre-Frac Checklist and Certification (Appendix 20). 

The conditions require and the checklists verify a number of important best practices for fracture 

treatments; however, additional NYS regulatory requirements should be considered to further refine the 

mitigation and codify these practices. 

NYSDEC should require operators to complete hydraulic fracture modeling prior to each fracture 

treatment to ensure that the fracture is contained to the Marcellus Shale zone and to collect data to further 

refine a hydraulic fracture model for the Marcellus Shale. These requirements should be added to NYS’s 

regulations. 

NYSDEC could either develop a Marcellus Shale fracture model that could be used as a standard for all 

operators, or it could require operators to collaboratively fund the development of a model. In either case, 

model(s) should be developed by a fracture expert and be peer-reviewed prior to use. Model(s) should be 

maintained, calibrated using field data, and continuously improved to ensure fracture prediction matches 

field implementation as closely as possible. 

Technology is available to assess actual fracture growth including: minifracs,77 microseismic fracture 

mapping,78 tilt surveys, well logging (e.g., tracer and temperature surveys79), etc.80 These technologies can 

be used to provide more accurate assessments of the locations, geometry, and dimensions of a hydraulic 

fracture system.81 This data can be obtained in the Marcellus Shale in a few different areas of NYS to 

further refine the hydraulic fracture model. Minifractures are particularly helpful in estimating fracture 

dimensions, fracture efficiency, closure pressure, and leakoff prior to implementing a high-volume, fullscale treatment. NYSDEC should require operators to conduct minifractures to better understand sitespecific reservoir characteristics prior to conducting a high-volume fracture treatment. 

The fracture treatment should be carefully monitored, and shut down if pressure data indicates casing 

leaks. The American Petroleum Institute recommends continuous and careful monitoring of surface 

injection pressure, slurry rate, proppant concentration, fluid rate, and sand or proppant rate, and 

immediate shutdown of the fracture treatment if abnormal pressures indicate a casing leak.82 

 

77 Minifracs are small fracture treatments conducted in the well to better understand fracture conductivity and flow 

geometry prior to implementing a large fracture treatment. Minifracs are typically used to optimize the fracture 

design and calibrate the fracture model. These tests involve periods of intermittent injection followed by intervals 

of shut-in and/or flowback. Pressure and rate are measured throughout a minifrac and recorded for subsequent 

analyses. 78 Microseismic monitoring is a method that measures the seismic wave generated during a fracture treatment to map 

the fracture extent, and it can be used to make “real-time” changes in the fracture design and implementation 

program. 79 After the fracture treatment is completed, an operator can run a temperature log in the well to measure the 

variation in reservoir temperature resulting from the treatment. The reservoir temperature is hotter than the 

fracture fluid and proppant. Cooler temperatures will be measured where frac fluid and proppant are placed. 

Temperature logs will provide insight into fracture location and growth outside the casing. 80 American Petroleum Institute (API) Guidance Document HF1, Hydraulic Fracturing Operations—Well 

Construction and Integrity Guidelines, October 2009. 81 Schlumberger, Microseismic Hydraulic Fracture Monitoring, 

http://www.slb.com/content/services/stimulation/stimmap.asp. 82 American Petroleum Institute (API) Guidance Document HF1, Hydraulic Fracturing Operations—Well 

Construction and Integrity Guidelines, October 2009. 
NYS DSGEIS Page 29 of 39 

Recommendation No. 18: NYSDEC needs to technically justify the proposed minimum 1,000’ 

vertical offset with actual field data, 3D reservoir simulation modeling and a peer-reviewed 

hydrological assessment to ensure drinking water sources are protected. 

Vertical Offsets Useful If Sized Correctly: The use of vertical offset limits to separate hydrocarbon 

recovery operations from drinking water aquifers is a good approach. However, the size of the vertical 

offset must be technically supported to ensure it is large enough to protect the drinking water aquifer. 

ICF recommended additional well-specific technical analysis for high-volume hydraulic fracture 

treatments conducted at depths less than 2,000’ TVD, or if the distance between the target fracture zone 

and a fresh water supply is less than 1,000’ TVD.83 ICF assumes that vertical fracture conducted in a 

horizontal section of a Marcellus Shale will not propagate more than 1,000’ and intersect a drinking water 

aquifer above. Yet ICF does not provide NYS specific 3D reservoir simulation modeling or field evidence 

(e.g., pressure data, microseismic fracture mapping, tilt surveys, history matching simulation, or tracer 

testing) to support its recommendation. ICF does not substantiate how it can guarantee that an operator 

will not implement a fracture out-of-zone or propagate above the Marcellus. ICF argues that the 1,000’ 

vertical buffer is a safe distance between the top of the Marcellus and a drinking water zone, but sitespecific data is needed to support this hypothesis. 

ICF argues that even if a fracture does propagate out-of-zone above the Marcellus, the fracture fluid will 

not migrate into the drinking water zone above, if at least 1,000’ vertical offset is maintained. ICF also 

argues that absent a direct fracture connection from the Marcellus to the drinking water aquifer, it would 

not be possible for contaminants to flow from the Marcellus to the overlying aquifer. Yet Tom Myers’ 

report for NRDC identifies a number of problems with ICF’s hydrological analysis and assumptions. 

Myers, a professional hydrologist, shows that it is possible for fracture fluids to naturally migrate toward 

the drinking water aquifer over time. Myers recommends additional data collection and analysis on this 

point. 

Moreover, while ICF recommends at least a 1,000’ vertical standoff to protect drinking water sources, 

there is no equivalent regulatory limit requiring this vertical buffer in NYSDEC’s proposed permit 

conditions (Appendix 10). If a vertical buffer is needed for drinking water protection, that limit should be 

clearly stated in NYS regulations. The 1,000’ vertical buffer zone must be technically justified or a larger 

vertical offset should be adopted to ensure drinking water standards are protected. 

Proper design and monitoring of hydraulic fractures is not only best practice from an environmental and 

health perspective, it is also good business because it optimizes gas production and reduces hydraulic 

fracture treatment cost. The most logical way forward is to limit development to the deepest Marcellus 

Shale intervals, maximizing the vertical separation from drinking water aquifers until an accurate, fieldcalibrated 3D reservoir simulation model is developed for designing fracture treatments in NYS. 

Drilling into the deepest, thickest Marcellus Shale intervals (e.g., below 4,000’) will maximize data 

collection on the Marcellus and all overlying intervals between the Marcellus and the drinking water 

aquifers. This will allow core samples, well logs, and pressure transient data to be obtained, verifying 

whether there are continuous permeability barriers hydraulically separating the Marcellus Shale and the 

overlying drinking water aquifers. 

 

83 DSGEIS, p. 7-49.
NYS DSGEIS Page 30 of 39 

Smaller fracture treatments should be tested, initially, increasing in size over time only when data is 

collected to support the conclusion that large fracture treatments can remain in zone. 

As data is collected, and 3D reservoir simulations models are developed and refined, it may be possible to 

safely develop the Marcellus at shallower depths and in thinner intervals. However, there is insufficient 

technical data in the DSGEIS to support development of shallow, thin sections of the Marcellus at this 

time. Neither NYSDEC nor its consultant team has demonstrated that high-volume hydraulic fracturing 

can be safely conducted in thin sections of the Marcellus Shale at depths as shallow as 2,000’ deep. 

14. Hydraulic Fracture Treatment Additive Limitations 

Recommendation No. 19: NYS regulations should identify the type, volume, and concentrations 

of fracture treatment additives that are protective of human health and the environment. NYS 

regulations should develop a list of prohibited additives and require the use of non-toxic materials 

to the extent possible.

DGEIS Section 5.384 states that NYSDEC collected compositional information from chemical suppliers 

and service companies on many of the additives proposed for use in shale fracture treatments. NYSDEC 

reports it has some compositional data on 197 products and complete compositional data on 152 products. 

Tables 5.3-5.7 provide lists of chemicals proposed for use in fracture treatments, and Section 5.4.3.1 

describes the potential health impacts of categories of chemicals. Yet the DSGEIS does not arrive at any 

recommendation or conclusion about which fracture treatment additives are acceptable for use in NYS 

and which are not. 

While Section 5.4.3.1 lists a number of potential adverse human health and environmental impacts, the 

mitigation measures proposed in Chapter 7 do not set limits on chemical use (volume or concentration) 

that are protective of human health and the environment. Chemical use should be limited to non-toxic 

chemicals that do not pollute the air or water. 

Section 9.3.185 briefly describes the possibility of using environmentally friendly chemicals, but rules this 

option out due to the lack of “green chemical” metrics in the US. 

Appendix 10, Proposed Permit Condition No. 32, limits the use of fracturing products to those identified 

in the well permit application, but it does not specify what chemicals are actually acceptable to include in 

a well permit application. This proposed permit condition appears to allow any fracturing product 

proposed by industry in a well permit application. 

This proposed permit condition also states that NYSDEC “may require a site-specific environmental 

assessment and SEQRA determination” prior to approving fracturing treatment chemicals that were not 

“previously reviewed.” It is not clear what is meant by “previously reviewed.” Does this mean fracture 

treatment chemicals “previously reviewed” in the DSGEIS? If this is the meaning, it raises serious 

concerns because, while the DSGEIS lists a number of fracturing products in Chapter 5, it does not make 

a toxicological decision about which chemicals are acceptable. In its current form, NYSDEC cannot rely 

on Chapter 5 to guide NYSDEC staff as to which fracturing treatment chemicals should be used. Chapter 

5 is merely a “laundry list” of chemicals currently used without an adequate review of the potential 

impacts on health or the environment. 

 

84 DSGEIS, p. 5-34. 

85 DSGEIS, p. 9-10. 
NYS DSGEIS Page 31 of 39 

There are several models in place that NYSDEC could use to develop regulations and standards for 

fracture fluid composition. For example, many government entities have adopted the Olso-Paris 

Convention (OSPAR) PLONOR list of environmentally friendly chemicals (chemicals considered to Pose 

Little Or No Risk to the marine environment) for screening chemical use in drilling and stimulation 

treatments. Other government entities prohibit use of chemicals that have harmful characteristics, such as: 

low biodegradability; high bioaccumulation potential; high acute toxicity; and detrimental mutagenic or 

reproductive affects. 

Best environmental practices can be implemented by developing a list of environmentally friendly 

chemicals that operators must comply with, as well as a list of chemicals that are prohibited. 

15. Hydraulic Fracture Fluid Flowback Surface Impoundments 

Recommendation No. 20: NYS regulations should require fracture fluid flowback be routed to 

onsite treatment systems for fracture fluid recycling and/or collected in tanks for transportation to 

offsite treatment systems. Surface impoundments should not be used for fracture fluid flowback. 

The DSGEIS does not present a consistent or clear recommendation on whether fracture fluid flowback 

impoundments are environmentally acceptable or allowed. The DSGEIS also leaves many other 

unanswered questions about what the expectations are for operators. Is the operator required to flow back 

fracture fluid to a tank? Are toxic chemicals allowed in impoundments? Is the operator required to stop 

using impoundments and flow to tanks? Is an operator required to complete site-specific modeling to 

better understand hazardous air pollutant impact from flowback impoundments? Or is an operator just 

required to build a larger fence to keep the public and wildlife away from the hazardous waste? 

Best technology for fracture flowback treatment is to eliminate the use of surface impoundments 

altogether. The use of temporary surface impoundments results in surface disturbance. It also has the 

potential for leakage to occur through or around the liner, impacting ground water and creating substantial 

amounts of hazardous air pollution. The BLM recommends the use of closed loop tank systems whenever 

possible.86 Fort Worth, Texas, prohibits frac fluid placement in an open pit.87

Fracture treatment flowback to metal tanks is an efficient collection method because fluid can be easily 

transferred to a treatment and disposal location, or taken to another well for reuse. Flowing fracture 

treatment fluid into a temporary reserve pit for later collection and disposal is inefficient, and creates the 

possibility of fracture fluids contaminating ground water (e.g. a leaking reserve pit liner). 

Of serious concern is the amount of hazardous air pollution predicted for these surface impoundments. 

Section 6.5.1.8 of the DSGEIS, “Potential Emission of Fracturing Water Additives from Surface 

Impoundments,” concludes that: 

“Based on an assumed installation of ten wells per wellsite in a given year, an annual methanol 

air emission [estimate] of 32.5 tons (i.e.,“major” quantity of HAP) is theoretically possible at a 

central impoundment”88 [emphasis added]. 

 

86 Bureau of Land Management, Surface Operating Standards and Guidelines for Oil and Gas Exploration and 

Development, The Gold Book, 2007. 87 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p. 9. 

88 DSGEIS, p. 6-56. 
NYS DSGEIS Page 32 of 39 

Section 6.5.2.2, “Sources of Air Emissions and Operational Scenarios,” states: “The Department has 

performed an assessment of a set of representative chemicals in the additives.” But, NYSDEC has not set 

any limits in the DSGEIS on the type of chemicals that can be used in fracture treatment; therefore, there 

is no assurance that NYSDEC’s subsequent air impact analysis at 6.5.2.3 is a worst case scenario or even 

representative of the emissions that will actually occur in the field (see analysis at pp. 6-75 though 6-76). 

While it is unclear if NYSDEC’s estimate of 32.5 tons of Hazardous Air Pollutants (HAPs) is even a 

worst case assessment, this is an unacceptably large amount of HAPs. NYSDEC’s HAPs finding, alone, 

should result in a mitigation measure that prohibits operators from using fracture fluid flowback 

impoundments, and requires operators to collect fracture fluid flowback into closed treatment systems 

and/or closed tanks for transport to a treatment system. 

This mitigation measure should be codified in NYS regulations. 

The DSGEIS acknowledges the human health and environmental exposure risks, and proposes several 

different solutions, but does not identify a solution that meets a best practices standard. In fact, its 

recommendations are inconsistent. 

For example: 

Section 7.5.3.2, “Centralized Flowback Water Surface Impoundments” states: 

“The EAF Addendum will require the operator to identify all proposed fracturing additives. 

Site specific review of potential HAP emissions will be based on these proposed additives (i.e., 

components and concentrations) and assessing air quality impacts of these compounds might be 

necessary, unless the same additive mix has been previously analyzed for a similar centralized 

impoundment. The EAF Addendum will also require the operator to identify proposed control 

measures for preventing public exposure to HAPs in excess of guidance thresholds. These could 

consist of eliminating specific compounds such as methanol, heavy naptha and benzene; 

limiting the duration and use of the impoundment; covering the impoundment or placing 

physical barriers”89 [emphasis added]. 

Section 7.5.3, “Summary of Air Quality Impacts Mitigation” proposes different mitigation: 

“If flowback impoundments are to be used, it will be necessary to exclude “solvent” and 

certain surfactants (containing benzene and xylene) from the current list of additives proposed 

by industry for use in fracturing operations. Furthermore, for the remaining chemicals, it is 

necessary to take steps to preclude public exposure to certain pollutant impacts by either 

eliminating their use or fencing in the impoundments. Specifically, for the smaller on-site 

impoundments, limiting public access to beyond approximately 150m from the impoundment 

would be one means of eliminating potential adverse impacts. On the other hand, for the larger 

centralized impoundment, public exposure to potential adverse impacts can be eliminated by 

erecting a fence at a rather large distance of approximately 1000m, or at a smaller distance if 

certain chemicals listed in Table 6.21, are eliminated. It is also determined that these larger offsite impoundments have the potential to qualify as a major source of Hazardous Air Pollutants 

(HAPs) due to certain chemicals. Thus, a case specific review might be required for these larger 

impoundments”90 [emphasis added]. 

 

89 DSGEIS, p. 7-90. 

90 DSGEIS, p. 7-89. 
NYS DSGEIS Page 33 of 39 

On p. 7-90, the DSGEIS provides yet a different conclusion: 

“However, as discussed elsewhere in this Supplement, uncertainties relative to potential 

flowback water volume and composition have led the Department to propose that flowback 

water not be directed to an on-site reserve pit but instead be held on the well pad in tanks prior 

to shipment to a disposal, treatment or re-use location”91 [emphasis added]. 

Section 7.1.7.4, “Use of Tanks Instead of Impoundments for Centralized Flowback Water Storage” then 

says: 

“Above ground storage tanks have some advantages over surface impoundments. The 

Department’s experience is that landfill owners prefer above ground storage tanks over surface 

impoundments for storage of landfill leachate. Tanks, while initially are more expensive,

experience fewer operational issues associated with liner system leakage. In addition, tanks 

can be easily covered to control odors and air emissions from the liquids being stored.

Precipitation loading in a surface impoundment with a large surface area can, over time, 

increase the volumes of liquid needing treatment. Lastly, above ground tanks also can be 

dismantled and reused. The provisions of Section 360-6.3 address the minimum regulatory 

requirements applicable to above ground storage tanks which would be equally applicable for 

adequate flowback water containment as well”92 [emphasis added]. 

Section 7.1.3.493 proposes fracture treatment flow back be routed to metal tanks, rather than reserve pits. 

NYSDEC’s consultant reports that the most common, current practice observed at Pennsylvania drilling 

sites is for the frac flowback to be contained in a closed system that captures the water in steel frac 

tanks.94 

The DSGEIS is unclear on what an operator will be required to do in terms of fracture fluid flowback. 

NYSDEC’s proposed application and mitigation system is cumbersome, time consuming, and labor 

intensive. It is not clear that NYSDEC has the staff needed to oversee permitting and enforce the new 

requirements proposed in this DSGEIS. A simplified, best practice approach of prohibiting, via 

regulations, surface impoundments for fracture fluid flowback is more cost effective and protective of 

human health and the environment. There could be a provision in the regulations for an operator to make 

a showing that it is technically infeasible to operate without fracture fluid flowback impoundments, and in 

these limited cases a more detailed assessment could be made at a site-specific level to determine if an 

impoundment is best technology for that situation. 

Please note that this recommendation does not include freshwater surface impoundments where water 

may be collected prior to adding fracture treatment chemicals. Operators developing the Marcellus Shale 

gas reservoir in Pennsylvania have found that: 

“The preferred method for delivery of water to the wellhead is to pump water directly from a 

withdrawal point on a surface water source through pipelines to an impoundment or tank battery 

near the well completion location. In order to pump efficiently, the surface water withdrawal 

point should be located within one mile of the storage. Direct pumping is the preferred method 

because it substantially reduces the risks and costs associated with bulk hauling by truck... Bulk 

 

91 DSGEIS, p. 7-90. 

92 DSGEIS, p. 7-55. 

93 DSGEIS, p. 7-34 and 7-35.

94 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.19. 
NYS DSGEIS Page 34 of 39 

hauling over public roadways is not the preferred method to supply source water for fracing as it 

can cause roadway damage, increased traffic congestion, air and noise pollution and increased 

safety risk.”95 

In areas where bulk hauling over public roadways is not a preferable environmental alternative, 

freshwater surface impoundments may be a reasonable option, because freshwater does not pose a risk of 

water or air pollution. However, NYSDEC should ensure there are adequate regulations for surface 

disturbance reclamation. 

Recommendation No. 21: The DSGEIS should disclose how many times a well may be fracture 

treated over its life, and provide a worst case scenario for water use and waste disposal 

requirements based on this scenario. 

The DSGEIS appears to report water use and waste volumes based on a single initial fracture treatment; 

this approach does not consider the fact that most shale gas wells require multiple fractures treatments. 

The DSGEIS should disclose how many times a well may be fracture treated over its life, and provide a 

worst-case scenario for water use and waste disposal requirements based on this scenario. It may be 

possible that repeat fracture treatments would not only dramatically increase water needs and disposal 

volumes, but also result in long-term use of impoundments pits. NYSDEC is not proposing to design 

impoundments for long–term use. 

16. Chemical Tank Containment 

Recommendation No. 22: NYSDEC should adopt regulations requiring secondary containment 

for chemicals stored on the well pad or, alternatively, the use of double-wall tanks. 

Chemicals, especially corrosive chemicals, can result in storage container leaks and spills to the 

environment. Best practice for permanent chemical storage is to install secondary containment under the 

storage container, and ensure the containers are not in contact with soil or standing water.96 NYSDEC’s 

consultant, Alpha, agrees on this point, yet Alpha’s recommendation does not materialize into a permit 

condition. Alpha’s report states: 

“It is recommended that regardless of exemption or regulatory status, the temporary on site 

storage of hydrofracing additive chemicals (and petroleum) comply with accepted best 

management practices (BMPs) for handling and spill containment. These practices may include, 

as appropriate to the specific containers, monitoring and recording inventories; manual 

inspections; berms or dikes, secondary containment; monitored transfers, storm water runoff 

controls, mechanical shut-off devices, setbacks, physical barriers, and materials for rapid spill 

cleanup and recovery.”97

Alpha specifically recommended that chemical tanks be placed in lined containment areas, sufficient to 

contain 110% of the single largest chemical container, and that the tanks be set back from a perennial or 

intermittent stream, private or public well, wetland, storm drain, lake, or pond. These important best 

 

95 Gaudlip, A.W., Paugh, L.O., and Hayes, T.D., Marcellus Shale Water Management Challenges in Pennsylvania, 

SPE Paper 119898, November 2008. 96 Bureau of Land Management, Surface Operating Standards and Guidelines for Oil and Gas Exploration and 

Development, The Gold Book, 2007. 97 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.36-37. 
NYS DSGEIS Page 35 of 39 

practice recommendations were not included, but should be, in the DSGEIS; they should also be codified 

in NYS regulations. Alternatively, double-wall tanks may provide another protective alternative. 

17. Reserve Pit & Impoundment Liner Quality 

Recommendation No. 23: NYSDEC should adopt regulations requiring closed-loop tank 

systems as a best practice instead of reserve pits and impoundments, unless the operator 

demonstrates that it is not technically feasible. 

The BLM recommends the use of closed loop tank systems as a best practice instead of reserve pits and 

impoundments, whenever technically feasible.98 Texas requires closed looped mud systems with steel 

tanks.99 It is much more efficient (from an energy standpoint) to collect waste in the container that will be 

used to transport it offsite to a waste disposal facility than it is to create an intermediate storage pit. The 

use of temporary reserve pits and impoundments results in surface disturbance. It also has the potential 

for leakage to occur through the liner, impacting groundwater. NYS regulations should require use of 

closed-loop tank systems, unless an operator can demonstrate is not technically feasible to operate 

without a reserve pit or impoundment. NYSDEC reports that some operators use closed loop tank systems 

to capture muds, cuttings, and flow back fluids (Section 5.2.3).100 This is a best practice that should be 

required for all operations. 

Recommendation No. 24: If reserve pits and impoundments are demonstrated to be 

environmentally preferable, NYSDEC should adopt regulations that require impermeable, 

chemical resistant liner material, and limit the type of chemicals stored to those compatible with 

the liner material; require wildlife protection design standards; and establish firm removal and 

restoration requirements. 

If there are cases where reserve pits and impoundments are necessary, liner quality should be specified. 

NYS regulations should specify under what circumstances closed-looped tank systems are not technically 

feasible, and specify that only under these limited circumstances, if any, should reserve pits and 

impoundments be used. In cases where reserve pits and impoundments are necessary, regulations should 

require the use of impermeable, chemical resistant liner material. Proposed Permit Condition No. 12 

establishes liner thickness and seam specifications, but does not specify liner quality. 

The DSGEIS notes that some drilling and stimulation chemicals can react with and damage reserve pit 

liner materials.101 The DGEIS reiterates the importance of installing impermeable liner material and 

ensuring the liner is maintained, repaired, and replaced.102 Yet, the proposed supplementary permit 

conditions do not include a requirement to install impermeable, chemical resistant liner material. 

The DSGEIS does not limit the types of chemicals that can be introduced into the reserve pits or 

impoundments. For example, used oils, paints, pipe dope, as well as toxic, corrosive, or bioaccumulating 

chemicals, should be prohibited. 

 

98 Bureau of Land Management, Surface Operating Standards and Guidelines for Oil and Gas Exploration and 

Development, The Gold Book, 2007. 99 Alpha Environmental Consultants, Inc., Report for NYS on DSGEIS, September 2009, p.8 states Fort Worth, 

Texas, requires closed tanks. 100 DSGEIS, p. 5-29 101 DSGEIS, p.7-29 102 DSGEIS, p.7-29 and p. 7-30 
NYS DSGEIS Page 36 of 39 

NYSDEC should list the type of chemical additives that are allowed to be temporarily stored in a reserve 

pit, and identify liner material specifications that will ensure the liner material is both impermeable and 

chemically resistant to those materials. 

• Proposed Permit Condition No. 16 requires fluids to be removed from the reserve pit, and the pit 

to be reclaimed within 45 days of drilling or stimulations operations, but does not specify what 

materials may actually be left in the reserve pit for long-term burial and storage. For example, 

Section 7.1.9 indicates that cuttings drilled with oil based muds cannot be stored in reserve pits, 

but it does not explain which type of muds and cuttings would be allowed for long-term disposal 

(e.g,. are all water based and synthetic muds and additives allowed?). 

• What type of testing will be required to ensure the material left in the reserve pit will not be 

harmful to the environment? For example, barite, a common ingredient in drilling muds, contains 

several heavy metals, including compounds of lead, cadmium, mercury, and arsenic.103 Will 

drilling mud solids containing lead, cadmium, mercury, and arsenic be allowed to be stored in the 

reserve pit on a long-term basis? 

• What type of testing will be conducted to demonstrate that the reserve pit liner was not damaged 

during use, and to ensure that the liner provides an impermeable barrier for long-term ground 

water protection? 

• What maintenance, testing and repair requirements will be put in place to ensure liner integrity? 

Unless there is an environmentally compelling reason to allow long-term disposal at onsite reserve pits, 

the preferred cleanup plan would be to remove all materials from temporary reserve pits, test waste 

material, and process it according to federal waste handling requirements at a licensed treatment and 

disposal site. 

If a reserve pit is determined to be an environmentally preferable temporary storage solution, the reserve 

pit should be fenced and netted to prevent wildlife and livestock from accessing the reserve pit. 

18. Wellbore Plugging & Abandonment Requirements 

Recommendation No. 25: NYS regulations should clearly state when future Marcellus Shale 

wells must be plugged and abandoned, and this should be retroactively applied to existing wells 

that are no longer operating and may pose a risk to the environment. 

Part 555 of 6 NYCRR requires gas wells to be permanently plugged and abandoned (P&A’d), but NYS’s 

regulations do not provide specific criteria to determine when a well must be P&A’d. An operator may 

submit a “Notice of Intention to Plug and Abandon” a well, but it appears to be a voluntary, operatorinitiated action. Alternatively, NYSDEC allows operators to shut-in wells or temporarily abandon wells 

without plugging, for what appears to be an indefinite time period. Historically, temporarily abandoned 

wells have been the source of environmental damage, because operators are not present to monitor 

wellbore integrity on a routine basis and wellbore infrastructure can corrode and erode, failing over 

time.104 

 

103 Rae, P. BJ Services Company, “Towards Environmentally-Friendly Additives for Well Completion and 

Stimulation Operations,” Society of Petroleum Engineering Paper 68651, 2001. 104 As a case in point, the 2009 catastrophic well leak in the Australian Timor Sea resulted from an improperly 

handled temporarily suspended well. 
NYS DSGEIS Page 37 of 39 

NYS regulations should clearly state the P&A requirements for a Marcellus Shale well. The regulations 

should define the best technology and practices for determining at what point in time a well must be 

P&A’d. The regulations should also specify the procedures required to properly abandon horizontal and 

multi-lateral wellbores. Most states limit temporary abandonment to a one-year period of time, with a 

wellbore integrity monitoring program requirement to ensure that the well is not leaking during temporary 

abandonment. 

The revised regulations should retroactively apply to existing wells that are no longer in operation and 

may pose a risk to the environment. As a priority, NYSDEC should carefully examine and require wells 

to be plugged and abandoned in close proximity to drinking water sources, and in areas under 

consideration for new high-volume fracture treatments. 

19. Well Control & Emergency Response Planning 

 

Recommendation No. 26: NYS regulations should be updated to include best practices for well 

control and emergency response planning. 

The DSGEIS does not require an emergency response plan, or well blowout control plan, in the event of a 

fire, explosion, or blowout. Best practices include developing and testing these types of plans prior to 

drilling. The capacity of local emergency response teams to take on potentially catastrophic fire and 

explosion hazards must be evaluated in the DSGEIS. NYSDEC must determine whether local emergency 

response capability exists, or if operators should be required to supplement emergency response with 

additional equipment, personnel, and training. 

Joint industry and local emergency response planning and training is considered best practice. It ensures 

local emergency response personnel and equipment will be able to provide support in an actual 

emergency, and that industry and local team response can be effectively and efficiently integrated.105 For 

example, well site roadways or access may be difficult for standard firefighting, rescue, and emergency 

medical services vehicles to access. Emergency response equipment may not have sufficient ground 

clearance to traverse the typically narrow dirt roads. Fire and rescue services should be aware of the areas 

and test drive the access roads to ensure that vehicles can gain access to sites. 

NYS regulations at 6 NYCRR § 556.2(c) require all gas wells capable of production to be equipped with 

wellhead controls adequate to contain and control gas flow. This regulation does not require an operator 

to install a fail-safe automatic surface controlled subsurface safety valve (SSSV) system capable of 

preventing an uncontrolled gas release in the event wellhead surface safety valves fail, or the wellhead is 

damaged. Many states require the use of SSSVs to provide a redundant prevention system. 

20. Hazardous Air Pollution Control 

Recommendation No. 27: NYS regulations should include best technology and practices to 

reduce hazardous air pollution to the lowest possible level. 

Dehydration Units: Dehydrator units are required to remove water moisture from the gas stream. 

Dehydrator units typically use triethylene glycol (TEG) to remove the water, and in the process the TEG 

 

105 Penn State Extension, Marcellus Shale: What Local Government Officials Need to Know; 

www.naturalgas.psu.edu. 2009. 
NYS DSGEIS Page 38 of 39 

absorbs methane, volatile organic compounds (VOCs), and hazardous air pollutants (HAPs); these gases 

are vented to atmosphere unless pollution controls are installed on the dehydration units. Best 

technology includes installation of flash-tank separators to recover the gas pollutants, or routing vapors 

to a vapor collection/destruction unit. 

The DSGEIS does not require installation of flash-tank separators to control hazardous air pollutants, 

and provides conflicting information on the estimated dehydration unit throughput. It’s also unclear as 

to whether or not pollution control will be required at a federal level. Section 6.5.1.2 of the DSGEIS 

concludes that dehydration units used for the gas development will be exempt from EPA’s National 

Emission Standards for Hazardous Air Pollutants (NESHAP) since gas production is estimated to be 

below 3 MMscfd106 and benzene emissions are estimated to be below 1 tpy. Yet, this conclusion 

conflicts with NYSDEC’s consultant report (ICF International’s August 2009, Subtask 2.5), that 

concludes: “Information gathered by NYSERDA and NYS DEC field trips to Marcellus Shale well sites 

indicate a potential production rate of 7 to 10 MMscf per day.” 

NYS regulations should require installation of flash-tank separators to control hazardous air pollutants. 

Alternatively, desiccant dehydrators can be used in place of TEG dehydrators; these units have shown to 

cost less, have lower operating and maintenance costs, and control 99% of HAPs.107

Impoundments: The DSGEIS estimates that a very large amount of hazardous air pollution (methanol) 

may be present at central impoundments (32.5 tons per year),108 and gives inconsistent approaches to 

pollution mitigation.109 EPA lists methanol as a hazardous air pollutant, but has not yet classified 

methanol with respect to carcinogenicity. The reproductive and developmental effect of methanol on 

humans is not understood.110 Testing in rats yielded skeletal, cardiovascular, urinary system, and central 

nervous system malformations.111 Chronic inhalation or oral exposure may result in headache, dizziness, 

giddiness, insomnia, nausea, gastric disturbances, conjunctivitis, blurred vision, and blindness in humans. 

Neurological damage, specifically permanent motor dysfunction, may also result.112

The EPA lists a major source of hazardous air pollution if more than 10 tons of a listed HAP is released 

per year. The DSGEIS proposes to allow the Marcellus Shale impoundment to pollute the air at a level 

more than three times this major source HAP threshold. The best practice is to use a closed loop 

collection and tank system, rather than impoundments. Vapors should be routed to an air pollution control 

device to filter or destroy HAPS. 

Benzene: The DSGEIS does not estimate significant amounts of benzene emissions; however, recent 

reports indicate the Texas Commission on Environmental Quality is finding surprisingly high levels of 

benzene emitted from Barnett Gas Shale activities in Texas.113 Additional analysis is warranted to better 

 

106 MMscfd= millions of standard cubic feet of gas per day. 107 Fernandez, R., Petrusak, R., Robinson, D., Zavadil, D., Cost-Effective Methane Emissions Reductions for Small 

and Midsize Natural Gas Producers, Journal of Petroleum Technology, June 2005. 108 DSGEIS, p. 6-57. 

109 DSGEIS at pgs. 7-55, 7-88, 7-89, and 7-90. 110 http://www.epa.gov/ttn/atw/hlthef/methanol.html 111 American Conference of Governmental Industrial Hygienists (ACGIH), TLVs and BEIs, Threshold Limit Values 

for Chemical Substances and Physical Agents, Biological Exposure Indices, Cincinnati, OH, 1999. 112 The Merck Index. An Encyclopedia of Chemicals, Drugs, and Biologicals. 11th ed. Ed. S. Budavari. Merck and 

Co. Inc., Rahway, NJ. 1989. 113 Dr. Michael Honeycutt, Head of TCEQ’s Toxicology Division, quoted in WFAA-TV new report, November 20, 

2009. Dr. Michael Honeycutt “was shocked to see air sampling revealed high levels of benzene, a cancercausing toxin, near some natural gas facilities.”
NYS DSGEIS Page 39 of 39 

understand and quantify the potential benzene exposure because it is a known, EPA-listed human 

carcinogen. Best control technologies should be identified and codified in regulation. 

21. Compressor Stations, Pipelines, and Gas Processing Facilities 

Recommendation No. 28: NYSDEC should include compressor stations, gathering pipelines, 

and gas processing facilities in the DSGEIS, and identify best technology and practices for this 

equipment. 

The DSGEIS states that compressor stations and pipelines are not within the scope of the DSGEIS. No 

best technologies or practices are evaluated. In its December 15, 2008 scoping comments to NYSDEC, 

the NRDC and co-signatories requested that gathering pipelines and gas treatment facilities be included 

and analyzed in the DSGEIS. NYSDEC should include compressor stations, gathering pipelines, and gas 

processing facilities in the DSGEIS, and identify best technologies and practices for this equipment. 

22. NYSDEC Inspection and Enforcement Program 

Recommendation No. 29: NYSDEC must demonstrate in the DSGEIS that it has the personnel, 

equipment, technical expertise, and funding to carry out the inspection and enforcement 

procedures listed in the DSGEIS. 

In its December 15, 2008 scoping comments to NYSDEC, the NRDC and its co-signatories requested the 

DSGEIS describe the current inspection program for gas wells including: budget, number of inspectors, 

inspector qualifications and expertise, and frequency of inspections. The DSGEIS does not demonstrate 

that NYSDEC has sufficient resources to oversee, inspect, and enforce Marcellus Shale gas development. 

A manpower and resource analysis specific to the Marcellus Shale gas development is needed. 

23. Financial Assurance Amount 

Recommendation No. 30: NYSDEC should require financial assurance adequate to fund longterm monitoring, publicly incurred response costs and the cost of properly remediating and 

abandoning operations. 

In its December 15, 2008 scoping comments to NYSDEC, the NRDC and its co-signatories requested the 

DSGEIS examine whether NYSDEC requires sufficient financial assurance (in the form of a bond or 

other financial instrument) to ensure there is funding available to properly plug and abandon wells, 

remove equipment and contamination, complete surface restoration, and compensate nearby public for 

adverse impacts (e.g., well contamination). Long horizontal wells are more costly to plug and abandon 

than vertical wells. Also, surface impacts will be larger due to planned high-volume fracture stimulation 

treatments, multiple wells drilled from a single well pad, and the need for additional gas treatment and 

transportation facilities. Some states require as much as $100,000 to cover a single well. Yet, the DSGEIS 

does not provide an analysis on the current financial assurance requirements.