Greater Natural Buttes 

Draft 

Environmental Impact Statement

DES 10-31 

Volume I 

(Chapters 1 through 9) 

Bureau of Land Management 

Vernal Field Office/Utah 

July 2010 
BLM Mission Statement 

The Bureau of Land Management is responsible for the stewardship of our public lands. It is 

committed to manage, protect, and improve these lands in a manner to serve the needs of the 

American people for all times. 

Management is based upon the principles of multiple use and sustained yield of our nation’s 

resources within a framework of environmental responsibility and scientific technology. These 

resources include recreation, rangelands, timber, minerals, watershed, fish and wildlife, wilderness, 

air and scenic, scientific, and cultural values. 
 

 

 

 

United States Department of the Interior 

BUREAU OF LAND MANAGEMENT
 

Vernal Field Office
 

170 South 500 East
 

Vernal, UT 84078 

(435) 781-4400 Fax: (435) 781-4410 

http://www.blm.gov/ut/st/en/fo/vernal.html
 

IN REPLY REFER TO: 

LLUTG01000 

1790 

UT-080-07-807 

Dear Public Land User: 

The Draft Environmental Impact Statement (EIS) for the Greater Natural Buttes Area Gas 

Development Project is hereby submitted for your review and comment. It was prepared to 

analyze the potential impacts of and alternatives to Kerr-McGee Oil & Gas Onshore LP’s 

proposed wellfield infill development scenario. The Greater Natural Buttes Project Area 

(GNBPA) encompasses approximately 162,911 acres in an existing gas producing area located in 

Township 8 South, Ranges 20 through 23 East; Township 9 South, Ranges 20 through 24 East; 

Township 10 South, Ranges 20 through 23 East; and Township 11 South, Ranges 21 and 22 East 

(Salt Lake Meridian) in Uintah County, Utah. 

This Draft EIS analyzes four alternatives in detail: the No Action Alternative, the Proposed 

Action Alternative (the Agency Preferred Alternative), a Resource Protection Alternative and an 

Optimal Recovery Alternative. The Draft EIS also contains a discussion of other alternatives that 

were considered but eliminated from detailed analysis. Under the Proposed Action, up to 3,675 

new gas wells would be drilled over a period of 10 years. Additionally, approximately 760 miles 

of new roads, 820 miles of buried pipelines, 587 miles of surface pipelines, 7 miles of electrical 

power lines, 2 mancamps, 2 compressor stations, and water disposal facilities would be 

constructed to support this proposed development. Total new surface disturbance under the 

Proposed Action would be approximately 12,658 acres, or 8% of the total GNBPA. 

The Draft EIS was prepared pursuant to the National Environmental Policy Act (NEPA), as well 

as other regulations and statutes, to address possible environmental and socio-economic impacts 

that could result from implementation of the project. This Draft EIS is not a decision document. 

Its purpose is to inform the public and the Decision Maker of the impacts associated with 

implementing the proponent’s drilling proposal, to evaluate alternatives to the proposal, and to 

solicit other agencies and the public for comments. 

If you wish to submit comments on this Draft EIS, we request that you make them as specific as 

possible, with references to page numbers and chapters of the document. The most useful 

comments will contain new technical or scientific information, identify data gaps in the impact 

analysis, or provide technical or scientific rationale for opinions or preferences. Please refer to 

“Greater Natural Buttes EIS” in your correspondence. Written comments will be accepted by fax, 
 

 

email, or letter for 45 days following the publication of the Notice of Availability in the Federal 

Register by the U.S. Environmental Protection Agency. Please provide your comments to: 

Bureau of Land Management 

Attn: Stephanie Howard 

Vernal Field Office 

170 South 500 East 

Vernal, Utah 84078 

Fax: 435-781-4410 

UT_Vernal_Comments@blm.gov 

Before including your address, phone number, email address, or other personal identifying 

information in your comment, you should be aware that your entire comment – including your 

personal identifying information – may be made publicly available at any time. While you may 

ask us in your comment to withhold your personal identifying information from public review, 

we cannot guarantee that we will be able to do so. BLM will not consider anonymous comments. 

Comments, including names and street addresses of respondents, will be available for public 

review at the BLM Vernal Field Office from 7:45 a.m. to 4:30 p.m. Monday through Friday, 

excluding federal holidays. Comments may be published as part of the NEPA document and 

other related documents. All submissions from organizations or businesses will be made 

available for public inspection in their entirety. For further information concerning the document, 

please contact Stephanie Howard at (435) 781-4469. 

 Sincerely, 

Michael G. Stiewig 

Vernal Field Office Manager 

Enclosures – As Stated 
Draft Environmental Impact Statement (EIS)
 

Kerr-McGee Oil & Gas Onshore LP (KMG) 

Greater Natural Buttes
 

Lead Agency: U.S. Department of the Interior Bureau of Land Management (BLM) 

Project Location: Uintah County, Utah 

Comments & Further Information 

On the Draft EIS: Stephanie Howard, Project EIS Team Lead 

Bureau of Land Management 

Vernal Field Office 

170 South 500 East 

Vernal, Utah 84078

 Phone: (435) 781-4400 

BLM Authorized Officer 

Responsible for Preparing 

the Draft EIS: Mike Stiewig, Field Manager 

Abstract 

KMG proposes to develop oil and gas resources within the 162,911-acre Greater Natural Buttes Project 

Area (GNBPA) located in Uintah County south of Vernal, Utah. The GNBPA is partially developed with 

1,562 existing oil and gas wells and associated infrastructure (including 23 compressor stations, access 

roads, water management facilities, pipelines, and power lines) with an estimated disturbance of 

7,766 acres. The Proposed Action would include the development of an additional 3,675 well pads at 

20-acre spacing and associated infrastructure. Construction would begin after the issuance of the Final EIS 

and Record of Decision, approval of individual Applications for Permit to Drill, and approved Right-of-Way 

grants. Construction would require approximately 10 years with the productive life of the project estimated at 

30 to 50 years. 

Four alternatives were analyzed in detail in this Draft EIS. They are the No Action Alternative, Proposed 

Action, Resource Protection Alternative, and Optimal Recovery Alternative. The No Action Alternative would 

consist of denying KMG’s proposed development of federal leases, but would include new development on 

federal leases (1,102 new wells and associated infrastructure) as disclosed through previously approved 

National Environmental Policy Act decision documents. The Proposed Action would consist of KMG’s 

proposal for developing the GNBPA. The Resource Protection Alternative would limit development to 

40-acre well pad spacing by utilizing directional drilling, thereby reducing the potential number of new single 

well pads and reducing the project disturbance. The Optimal Recovery Alternative would involve 

development of new well pads on 10-acre well spacing to maximize the recovery of hydrocarbon resources, 

thereby increasing project disturbance. Under all alternatives, development would continue on State and 

private leases including roads and pipelines crossing federal lands to access the State and private leases. 

In addition to KMG’s commitment to voluntarily apply the applicant-committed environmental protection 

measures listed in Appendix A of this document, mitigation is recommended that would lessen the 

environmental effects of the proposed project. 

Written comments on the Draft EIS will be accepted by the Vernal Field Office of the BLM throughout a 

45-day public comment period beginning on the date the United States Environmental Protection Agency 

publishes a Notice of Availability for this EIS. A summary of the comments and responses to the comments 

will be provided in the Final EIS. 
 

 

Executive Summary 

Kerr-McGee Oil & Gas Onshore LP (KMG), a wholly owned subsidiary of Anadarko Petroleum Corporation, 

has notified the Bureau of Land Management’s (BLM) Vernal Field Office that it proposes to conduct infill 

drilling to develop the hydrocarbon resources from oil and gas leases owned, at least in part, by KMG within 

the Greater Natural Buttes Project Area (GNBPA) in Uintah County, Utah (Figure ES-1). KMG intends to 

develop all potentially productive subsurface formations underlying the GNBPA. The formations include, but 

are not limited to, the Green River Formation, Wasatch Formation, Mesa Verde Group (including the 

Blackhawk Formation), Mancos Shale, and Dakota Sandstone. 

The GNBPA consists of approximately 162,911 acres in an existing gas producing region located on lands 

owned by the federal government, the State of Utah, the Ute Tribe, and other private land owners. Federal 

lands in the proposed GNBPA are under the jurisdiction of the BLM Vernal Field Office. The Vernal Field Office 

has determined that the proposed project constitutes a major federal action requiring the development of an 

environmental impact statement (EIS). This EIS serves the purpose of disclosing and analyzing impacts 

resulting from the level of development proposed within the GNBPA, including a no action alternative, with 

consideration of identified and applied applicant-committed environmental protection measures (ACEPMs) and 

recommended mitigation measures. A summary of these ACEPMs is provided in Appendix A. 

Purpose and Need 

The need for a BLM action is to respond to this proposal and to evaluate action on future plans and 

applications related to this proposal. The Federal Land Policy and Management Act of 1976 (Public 

Law 94-579, 43 United States Code [USC] 1701 et seq.) recognizes oil and gas development as one of the 

"principal" uses of the public lands. Federal mineral leasing policies (Mineral Leasing Act of 1920, 30 USC 188 

et seq.) and the regulations by which they are enforced recognize the statutory right of lease holders to 

develop federal mineral resources to meet continuing national needs and economic demands. The purpose of 

this EIS is to facilitate the BLM decision-making process of whether to approve, approve with modifications, or 

disapprove the proposed project or project components based on an evaluation of the expected impacts. 

Through this process, the BLM's purpose is to minimize or avoid environmental impacts to the extent possible, 

while allowing KMG to exercise its valid lease rights. 

KMG, a private corporation, proposes development of their leases in the GNBPA for the purpose of making a 

profit on the extraction and sale of oil and gas resources. In addition to developing the subsurface resources in 

the GNBPA and testing directional drilling technologies, KMG’s proposed project would increase the supply of 

domestic natural gas and liquid hydrocarbons and contribute to the economic vitality of the local communities 

through increased employment opportunities and expanded tax bases. KMG’s proposed natural gas and oil 

development project is consistent with the National Energy Act of 2005 and the National Energy Policy 

(President’s Plan) because it would provide a domestic source of natural gas and oil to meet rising national 

energy demand. 

Scoping 

The BLM conducted public and internal scoping to solicit input and identify environmental issues and concerns 

associated with the proposed project. The public scoping process was initiated on October 5, 2007, with the 

publication of a Notice of Intent in the Federal Register. The BLM prepared a scoping information notice and 

provided copies to the public, other government agencies, and Tribes. These announcements included 

information on a public scoping and open house, which was held at the Western Park Conference Center in 

Vernal, Utah, on October 23, 2007. The official scoping period ended November 5, 2007. Written comments 

were received during the public scoping period consisting of nine letters: two from federal agencies, 

DEIS ES-1 July 
 2010 
Green River 

Green vi er 

White River 

Green River 

Green River 

Colorado 

Rio Blanco 

County

R

County Greystone

191 

Maeser Whiterocks Vernal

Neola Naples 149 

Lapoint121 

Jensen 

40 Roosevelt 40

Fort Massadona Duchesne 262 Blue Ballard Dinosaur Mountain Randlett 

88 

Myton 

45 64 

Rangely Ouray 

Sweetwater 

County 

City or Town 

Major River 

Highway 191 Major Road Burntfork 530 Wyoming State Boundary 

County Boundary McKinnon 

43 Manila Utah Hiawatha Project Boundary

44 Daggett 318 

County 

Moffat 

County 

Uintah 

Duchesne Bonanza

County 

Carbon 

County 

0 2.5 5 10 15 

Scale in Miles 

Greater Natural Buttes 

Area Gas Development

Project EIS
 

Figure ES-1 

Regional Location Map 

ES-2

Tuesday, May 6, 2008 2:15:52 PM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\APDEIS_Figures\Fig1_1-1_ProjectLocation.mxd 
 

one from state agencies, one from a county agency, one from a non-governmental organization, and four from 

industry or private individuals. During the scoping period, key concerns were identified for consideration in 

preparing the Greater Natural Buttes EIS. 

The BLM conducted internal scoping to compile a list of resources potentially present in the Vernal Field Office 

area to be considered in this EIS. Based on this list, the following resources are discussed and analyzed in 

Chapters 3.0, 4.0, and 5.0 of this document: 

• Air Quality; 

• Cultural Resources and Native American Traditional Values; 

• Geology; 

• Land Use; 

• Paleontology; 

• Range Resources; 

• Recreation; 

• Socioeconomics and Environmental Justice; 

• Soils; 

• Transportation and Access; 

• Vegetation Resources; 

• Visual Resources; 

• Water Resources; 

• Wilderness Characteristics; and 

• Wildlife and Fisheries Resources. 

The BLM has determined that the proposed project is in conformance with the BLM management plans and 

policies and is consistent with other federal and local land management plans and policies. As allowed under 

36 Code of Federal Regulations (CFR) 800.8, the BLM will use the public comment process under the National 

Environmental Policy Act (NEPA) to comply with the public consultation requirements of Section 106 of the 

National Historic Preservation Act. 

Proposed Action and Alternatives 

Chapter 2.0 of this EIS describes the existing and approved oil and gas facilities and the proposed 

development alternatives, including a no action alternative, analyzed in this document. In developing the 

alternatives, the BLM followed guidance set forth in 40 CFR 1500-1508 and the BLM NEPA Handbook 

H-1790-1 (BLM 2008a). The BLM Instruction Memorandum No. 2005-247, Attachment 1, also provides 

recommendations on developing a range of reasonable alternatives for oil, gas, and geothermal development 

activities. Based on this guidance, the BLM developed four alternatives for analysis in this EIS as described in 

the following paragraphs. The BLM preferred alternative is the Resource Protection Alternative. 

Existing oil and gas infrastructure in the GNBPA (as of October 2007) consists of 1,562 vertical productive 

wells generally drilled on single well pads. Supporting infrastructure associated with this existing development 

includes access roads, mancamps, compressor stations, a gas processing plant, water management facilities 

(evaporation, recycling, and injection), gas and water pipelines, and power lines. The existing surface 

disturbance in the GNBPA as of October 2007 is estimated at 7,766 acres or about 4.8 percent of the GNBPA. 

This date was selected as a fixed point in time to represent information that is continuously changing. While 

DEIS ES-3 July 
 2010 
 

 

 

the BLM recognizes there is a gap between this point in time and the publication date of this document, the 

information provides a consistent basis for evaluation of the proposed project and alternatives. 

No Action: Under the No Action Alternative, drilling and completion of development wells and infrastructure 

would continue as described in approved NEPA decision documents. An estimated 1,102 wells remain to be 

drilled in addition to the 1,562 existing wells in the GNBPA (as of October 2007). Supporting infrastructure 

associated with this alternative includes access roads, compressor stations, water management facilities 

(evaporation, recycling, and injection), gas and water pipelines, and power lines. Because reclamation is 

difficult to achieve in the Uinta Basin, all disturbance is assumed to be present for more than 3 years, typically 

for the life of the project. The total estimated new surface disturbance for the No Action Alternative would be 

approximately 4,702 acres or about 2.9 percent of the GNBPA. 

Proposed Action: This alternative consists of KMG’s proposed infill drilling project within the GNBPA to 

develop an additional 3,675 wells drilled from a maximum of 3,041 new well pads placed at up to 20-acre 

surface spacing. KMG and other operators would drill additional wells at an average rate of approximately 

358 wells per year over a period of 10 years or until the resource base is fully developed. The productive life of 

each well is estimated to be approximately 30 to 50 years. In support of the new wells, KMG would construct 

access roads, pipelines, electric power lines, compression facilities, and water disposal facilities. The total 

estimated new surface disturbance for the Proposed Action would be approximately 12,658 acres or about 

7.8 percent of the GNBPA. 

Portions of the GNBPA pose environmental constraints to drilling a vertical well from the surface, based on the 

following factors: 

•	 Topography, including steep slopes that preclude construction of a well pad for a vertically drilled well 

without major cuts-and-fills; 

•	 The viewshed (line-of-sight from the centerline up to 0.5 mile along both sides of the river) of the White 

River corridor, outside of the Indian Trust Lands; and 

•	 Areas within 600 feet of the White River within the Indian Trust Lands. 

In areas where the gas resources in the reservoirs warrant a downhole spacing of less than 20 acres based on 

reservoir engineering evaluation, or in those areas where environmental constraints preclude vertical wells, 

KMG would test and attempt to utilize directional drilling technology. Analysis of the Proposed Action 

Alternative assumes vertical wells would be drilled at all 3,041 new well pad locations. 

Resource Protection Alternative: This alternative consists of the same number of wells as the Proposed 

Action (3,675 wells) but surface well pads would be limited to 40-acre spacing, resulting in a reduced number 

of well pads (approximately 1,484 well pads) and a reduction in the surface disturbance of the project. If full 

recovery of the natural gas resource requires the drilling of wellbores at a downhole spacing of 20 acres or 

less, then directional drilling techniques would be required under this alternative. Therefore, impact analysis of 

this alternative assumed 1,557 directionally drilled wellbores to establish the same number of wellbores 

(3,675) as the Proposed Action Alternative. 

As discussed under the Proposed Action Alternative, KMG and other operators would drill additional wells at 

an average rate of approximately 358 wells per year over a period of 10 years or until the resource base is fully 

developed. The estimated productive life of each well would be approximately 30 to 50 years. The disturbance 

impacts associated with production facilities (mancamps, compressor stations, water tank batteries, and water 

disposal wells) as well as electrical power requirements is expected to be the same for this alternative as it 

would be for the Proposed Action Alternative. The total estimated new surface disturbance for the Resource 

Protection Alternative would be 8,147 acres or about 5 percent of the GNBPA. 

DEIS	 ES-4 July 2010 
 

 

The location of the 40-acre spaced well pads for this alternative would reflect avoidance of the following 

constraining factors: 

•	 Topography, including steep slopes that preclude construction of a well pad for a vertically drilled well 

without major cuts-and-fills; 

•	 The viewshed of the White River corridor (line-of-sight from the centerline up to 0.5 mile along both 

sides of the river), outside of the Indian Trust Lands; 

•	 Areas within 600 feet of the White River within the Indian Trust Lands; and 

•	 Areas within the 100-year floodplain of the White River and 5 miles up major tributaries. 

Optimal Recovery Alternative: This alternative maximizes the recovery of natural gas resources by 

increasing surface well pad spacing to 10 acres throughout the GNBPA. Assuming a vertical well would be 

drilled from each new well pad, KMG and other operators would drill an estimated 13,446 new wellbores within 

the GNBPA. KMG’s activities would remain largely as outlined under the Proposed Action Alternative. 

Additional wells would be drilled at an average rate of approximately 672 wells per year using 28 drilling rigs 

and would be drilled over a period of approximately 20 years or until the resource base is fully developed. The 

estimated productive life of each well would be approximately 30 to 50 years. The drilling schedule, well drilling 

and completion parameters, equipment and manpower requirements, compressor stations, water disposal 

facilities, buried water and gas pipelines, electric power facilities, and ancillary facilities would be similar to that 

for the Proposed Action Alternative, but in some cases, more facilities would be constructed because of the 

higher number of wells and increased gas volumes produced under this alternative. The total estimated new 

surface disturbance for the Optimal Recovery Alternative would be 42,620 acres or about 26 percent of the 

GNBPA. 

Alternatives Considered but Eliminated from Detailed Analysis: The BLM considered two alternatives to 

the proposed project that were not carried forward for detailed analysis in subsequent chapters of this 

document. One of these alternatives was one in which no further development would take place in the 

GNBPA. This alternative is not the same as the No Action Alternative, which is required under NEPA and is 

fully analyzed in this document. The No Action Alternative would occur if the BLM were to deny KMG’s 

proposal. The no further development alternative was eliminated from detailed analysis because ongoing 

development continues on valid leases within the GNBPA as disclosed under existing NEPA decision 

documents (Section 2.4.1). 

The BLM also considered a phased development alternative, which was intended to rotate concentrated 

disturbance activities through smaller, pre-defined areas (subareas) while the remainder of the GNBPA would 

be less impacted than under the Proposed Action. Under this alternative, one subarea at a time would be open 

to oil and gas construction and development activities for a limited time period, after which construction and 

development activities would cease. Oil and gas extraction and processing would continue (i.e., operational 

activities) in the subarea, while construction and development activities would move to another subarea. An 

additional intent was to encourage concurrent and efficient reclamation of surface disturbance. This 

alternative was eliminated from detailed analysis because the BLM could not impose phased development on 

almost one-half (45 percent) of the GNBPA, phased development could delay surface owner benefits (such as 

payments or hiring preferences for Ute Tribe members), production and maintenance activities would continue 

throughout the currently developed areas of the GNBPA, and development would be concentrated on 

individual grazing allotments (Section 2.9). 

Affected Environment 

Chapter 3.0 of the EIS describes the affected environment of the GNBPA for each of the resources identified 

during internal scoping and listed above. These resources are present within the GNBPA and provide the 

basis to address substantive issues of concern brought forward during internal and public scoping. The 

information presented in Chapter 3.0 provides quantitative data and spatial information where appropriate to 

DEIS	 ES-5 July 
 2010 
 

 

 

 

 

 

the resource that serves as a baseline for comparison of the direct, indirect, and cumulative impacts of each of 

the alternatives. 

Environmental Consequences 

Chapter 4.0 describes the environmental effects of implementing the alternatives on the affected environment 

as described in Chapter 3.0. The chapter is divided into subsections addressing the specific incremental 

impacts for each of the resources identified during internal scoping listed above. For each resource, the impact 

analysis was focused on the new disturbance associated with the No Action Alternative, which is over and 

above the existing disturbance in the GNBPA. For each of the action alternatives (Proposed Action, Resource 

Protection Alternative, and Optimal Recovery Alternative), the new disturbance is over and above the existing 

disturbance and the new disturbance associated with the No Action Alternative. The resource-specific effects 

of the alternatives are evaluated quantitatively and qualitatively, as appropriate based on available data and 

the nature of the resource analyzed. A comparison of disturbance within the GNBPA associated with the four 

alternatives is provided in Table ES-1. A summary of the Chapter 4.0 impact analyses is provided in 

Table ES-2. 

Cumulative Impacts 

Cumulative impacts from past, present, and reasonably foreseeable development are presented in 

Chapter 5.0 of the Draft EIS. For each resource, the Cumulative Impact Study Area (CISA) was developed 

appropriate to the geographical extent of anticipated cumulative impacts. For some resources (e.g., cultural 

resources and Native American traditional values, geology, paleontology, soils and vegetation), the CISA is the 

same as the GNBPA. For other resources (e.g., socioeconomics and air quality), the CISA includes the 

majority of the Uinta Basin, which encompasses the Vernal planning area. 

Due to the intensity of energy development activity in the Vernal planning area, the focus of this analysis is on 

past, present, and reasonably foreseeable oil and gas development. A total of 18,666 well pads and 

82,833 acres of cumulative surface disturbance, including the Proposed Action, is estimated to occur due to 

past, present and reasonably foreseeable projects in the Vernal planning area. The Proposed Action would 

represent approximately 20 percent of the total number of well pads and 15 percent of the cumulative surface 

disturbance in the Vernal planning area. The Proposed Action would represent approximately 48 percent of 

the 26,411 acres of cumulative surface disturbance (i.e., existing, No Action, and Proposed Action) in the 

GNBPA. 

The 6.07 trillion cubic feet (Tcf) of natural gas production over the life of the project under the Proposed Action 

is approximately equivalent to total production for a single year for the entire Mountain region (Utah, North 

Dakota, South Dakota, Montana, Wyoming, Idaho, Nevada, Colorado, Arizona, and western New Mexico). 

Alternatively, the average annual production under the Proposed Action would represent 3 to 4 percent of the 

annual regional production over the next two decades. Over the first 30 years of the project, the average 

annual production for the Proposed Action would be equivalent to approximately 40 to 45 percent of the 

442 billion cubic feet annual gas production for the State of Utah in 2008. 

Below is a summary of cumulative impacts for key resources: 

•	 Air Quality: Cumulative impacts to air quality as predicted from modeling would remain below air 

quality standards under all alternatives except the Optimal Recovery Alternative, for which there is a 

potential to exceed the standard for ozone (75 parts per million). Cumulative visibility modeling shows 

that the No Action Alternative would dominate regional haze impacts at Class I areas, whereas 

incremental visibility impacts from the action alternatives would be less than 1.0 deciview (dv). 

Cumulative acid deposition as predicted from modeling would be below established comparative 

deposition values at all Class I and Class II areas within the vicinity of the GNBPA. 

•	 Range Resources: The 12 grazing allotments that make up the CISA for range resources 

encompass an area of 470,228 acres. Total cumulative disturbance to these allotments, including 

DEIS	 ES-6 July 2010 
 

 

 

impacts from the Proposed Action, would be 37,261 acres; resulting in the loss of 3,149 active animal 

unit months (AUMs). The Proposed Action would account for 1,018 AUMs, or approximately 

32 percent of the total cumulative AUMs lost. Under the Resource Protection Alternative, the proposed 

project would account for 655 AUMs lost (24 percent of the total cumulative loss); under the Optimal 

Recovery Alternative, the proposed project would account for 3,425 AUMs lost (62 percent of the total 

cumulative loss). 

•	 Vegetation: The Proposed Action would represent approximately 48 percent of the 26,411 acres of 

cumulative vegetation loss; the Resource Protection Alternative would represent 37 percent of the 

21,900 acres of cumulative vegetation loss; and the Optimal Recovery Alternative would represent 

76 percent of the 56,373 acres of cumulative vegetation loss within the GNBPA. While cumulative 

surface disturbance, particularly linear disturbances such as pipelines, roads, transmission lines and 

seismic surveys, have the potential to spread noxious weeds and invasive species, these impacts 

would be minimized through the use of wash stations to control mechanical spreading of seeds, 

herbicide spraying, and reclamation of disturbed areas. 

•	 Water: Cumulative impacts to surface water quantity due to past, present, and reasonably 

foreseeable oil and gas development activities would be minor because the majority of water use 

would be limited and short-term in nature as well as substantially less than other demands (particularly 

agricultural) in the Uintah County region. Compliance with spill prevention and clean-up programs, 

stormwater management plans, and construction best management practices would reduce 

cumulative impacts to surface water quality. Increased injection of produced water into subsurface 

saline aquifers would increase aquifer storage; however, due to implementation of the United States 

(U.S.) Environmental Protection Agency’s Underground Injection Control program, impacts to 

underground sources of drinking water would not be anticipated. 

•	 Wildlife: Cumulative impacts to wildlife resources would be directly related to habitat loss, habitat 

fragmentation, and animal displacement associated with increased surface disturbance. Within the 

CISA for wildlife and fisheries, the Proposed Action would represent approximately 15 percent of the 

82,833 acres of cumulative surface disturbance; the Resource Protection Alternative would represent 

approximately 10 percent of the 78,322 acres of cumulative surface disturbance; and the Optimal 

Recovery Alternative would represent approximately 38 percent of the 112,795 acres of cumulative 

surface disturbance. 

Cumulative impacts to fisheries resources include erosion and sedimentation from increased 

surface disturbance, water depletions from the White and Green rivers, and the potential leaks and 

spills of contaminants from facilities or development activities. Due to the presence of federally 

endangered fish species in the White and Green rivers, these cumulative impacts would be 

minimized by the protection measures required by the BLM and U.S. Fish and Wildlife Service. 

Total water depletions of 757 acre-feet/year under the Proposed Action and Resource Protection 

alternatives, and 1,385 acre-feet/year under the Optimal Recovery Alternative, would account for 

less than 1 percent of the total water depletions (182,603 acre-feet/year) within the White and 

Green rivers. 

DEIS	 ES-7 July 2010 
Table ES-1 Disturbance Comparison for GNBPA Alternatives (Excluding Existing Condition) 

New Facilities 

Size 

(ROW width 

[feet] or 

acres/facility) 

New Surface Disturbance by Alternative 

No Action Proposed Action Resource Protection 

Multiplier 

(number or 

miles) 

Disturbance 

(acres or % 

of GNBPA) 

Multiplier 

(number or 

miles) 

Disturbance 

(acres or % 

of GNBPA) 

Multiplier 

(number or 

miles) 

Disturban

(acres or 

of GNBPA

Roads 

Access Roads1 45 feet 276 miles 1,503 760 miles 4,147 594 miles 3,238 

Well Pads 

New Single Well Pads 2.5 acres 1,102 each 2,755 3,041 each 7,603 1,484 each 3,710 

Twinned Well Pads (Additional Disturbance) 0.2 acre 0 each 0 634 each 127 634 each 127 Multi-well Pads (Additional Disturbance) 0.2 acre 0 each 0 0 each 0 1,557 each 311 

Well Pad Subtotal 1,102 each 2,755 3,675 each 7,729 3,675 each 4,148 

Construction/Production Facilities 

Mancamps 5 acres 0 each 0 2 each 10 2 each 10 Compressor Stations 20 acres 6 each 120 2 each 40 2 each 40 

Water Tank Batteries 3 acres 8 each 24 2 each 6 2 each 6 Water Injection Facilities (Additional Disturbance) 0.2 acre 0 each 0.0 15 each 3 15 each 3 

Construction/Production Facilities Subtotal 144 59 59 

Linear Facilities 

Gas Gathering Pipelines – Common ROW 0 feet 262 miles 0 722 miles 0 564 miles 0 Gas Gathering Pipelines – Cross-country 20 feet 14 miles 33 38 miles 92 30 miles 72 

Gas Transport Pipelines (Buried) 75 feet 0 miles 0 35 miles 318 35 miles 318 Water Gathering Pipelines – Common ROW (Surface) 0 feet 0 miles 0 587 miles 0 458 miles 0 

Water Connecting Pipelines (Buried) 75 feet 26 miles 236 25 miles 227 25 miles 227 Electric Power Lines 100 feet 2.5 miles 30 7 miles 85 7 miles 85 

Linear Facilities Subtotal 300 722 702 

New Surface Disturbance (acre) 4,702 12,658 8,147 

GNBPA New Disturbance (%) 2.9% 7.8% 5.0% 

No Action Alternative New Disturbance (acre) 4,702 4,702 

Existing Surface Disturbance (acre) 7,766 7,766 7,766 

Total Surface Disturbance (acre) 12,468 25,125 20,615 

Total GNBPA Disturbed (%) 7.7% 15.4% 12.7% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable New Surface Disturbance (acre) 1,753 4,731 3,387 

Reclaimable No Action New Surface Dist (acre) 1,753 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 3,267 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 5,020 9,751 8,407 

Reclaimable Surface Disturbance (%) 40.3% 39% 41% 

Reclaimable Surface Dist as % of GNBPA 3.1% 6.0% 5.2% 

1 Assume access road length of 0.25 mile/well pad for No Action and Proposed Action; 0.4 mile/well pad for Resource Protection Alternative; 0.127 mile/well pad for Optimal Recove2 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear Facilities summarized in the t

DEIS ES-8 
Table ES-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Air Quality 

Air Quality (exceed National Ambient Air Quality Standards) No No No Potential1 Sect

Acid Deposition (exceed U.S. Forest Service threshold) Yes (1 area)2 Yes (1 area)2 Yes (1 area)2 Yes (1 area)2 SectVisibility (Class I) Cumulative Incremental impacts Incremental impacts Incremental impacts Sect

impacts > 1.0 dv < 1.0 dv < 1.0 dv < 1.0 dv 

Visibility (Class II) Cumulative Incremental impacts Incremental impacts > Incremental impacts Sect

impacts > 1.0 dv > 1.0 dv at 2 areas 1.0 dv at 2 areas > 1.0 dv at 2 areas 

Greenhouse Gas Emissions (103 tonne carbon dioxide 

equivalents/year) 

1,761 2,754 2,754 5,485 Sect

Cultural Resources and Native American Traditional Values 

Sites potentially encountered (incremental due to new surface disturbance) 

52 142 90 475 Sect

Geology 

Recoverable Gas Resources Over the Life of the wells (Tcf) 1.41 6.07 6.07 15.44 Sect

Recoverable Condensate Resources Over the Life of the Wells 22.3 86.5 86.5 118 Sect(million barrels [bbl]) 

Land Use 

White River Special Recreation Management Area (incremental acres disturbed) 

7.8 49 32 164 Sect

Paleontology 

Potential Fossil Yield Classification Class 4 or 5 areas (potential 4,467 12,025 7,740 40,489 Sect

incremental acres disturbed) 

Range Resources 

AUMs Lost – BLM 352 947 609 3,186 Tab

AUMs Lost – BIA 26 71 46 239 Tab

Total AUMs Lost 378 1,018 655 3,425 

Number Rangeland Improvements Impacted (BLM land only) NA 26 15 27 Tab

Socioeconomics 

Energy Resource Recovery Sect

Natural Gas (Tcf) 1.41 6.07 6.07 15.44 Oil Condensates (million bbl) 22.3 86.5 86.5 117.9 

Projected end of production (year) 2051 2059 2059 2066 

Employment (number jobs) Sect

and 

Peak – development 1,790 4,302 4,302 9,024 

Average – production 239 875 875 1,712 

Population – Duchesne and Uintah counties Sect

and 

Peak – development 2,585 5,590 5,590 8,368 Average – production 450 1,508 1,508 2,732 

DEIS ES-9 
Table ES-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Temporary and permanent housing demand in Duchesne and Uintah counties during development (units) 

1,593 3,447 3,447 5,159 Sect

and 

Grazing – Reduction in annual cash farm receipts ($24 per As much as As much as As much as As much as Sect

AUM lost) $7,632 lost $24,432 lost $15,720 lost $82,200 lost Public Sector Revenues – Cumulative Life of Field3 (millions of 

2006 dollars) 

Sectand 

Ad Valorem Taxes 89.2 343.8 343.8 856.1 Utah Severance Taxes 270.5 1,146.7 1,146.7 2,709.5 Federal and Tribal Mineral Royalties 417.9 2,692.4 2,692.4 6,333.9 State Public School Fund Royalties 158.9 673.1 673.1 1,582.5 

Combined Public Sector Revenues 1,154.3 4,856.0 4,856.0 11,481.0 

Percent Increase over No Action N/A 321 321 895 

Soils 

High Constraint (incremental acres disturbed) 4,396 11,835 7,618 39,849 Tab

Moderate Constraint (incremental acres disturbed) 141 380 244 1,279 Low Constraint (incremental acres disturbed) 165 443 285 1,492 

Transportation and Access 

New Access Roads (miles) 276 760 594 1,627 Sect

Increase in Traffic Volume at Full Production (total number 0 20,948 20,948 59,162 Sect

vehicle miles) Number of Annual Incidents (mostly minor accidents and spills) 22 58 58 201 Sect

Vegetation 

Uinta Basin hookless cactus potential preferred habitat 1,576 4,369 2,731 14,201 Sect

(estimated incremental acres disturbed) Vegetation Type (estimated incremental acres disturbed) Tab

Salt-desert shrubland 1,932 5,279 3,437 17,775 Sagebrush shrubland 1,663 4,548 2,961 15,313 

Grassland 455 1,246 811 4,194 Cliff/Canyon 217 593 386 1,997 

Riparian 143 189 29 637 

Pinyon-juniper woodland 82 225 147 758 

Agriculture 30 81 53 274 Barren 178 490 319 1,650 Developed 2 7 4 22 

Visual Resources 

Visual Resource Management Class II areas on federal lands (incremental acres disturbed) 

0 91 58 305 Sect

Incremental Disturbance Visible from (acres): Sect

Boaters on the White River 1,287 3,461 2,218 11,536 

Goblin City Overlook 140 377 242 1,257 

DEIS ES-10 
Table ES-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Water Resources 

Surface Water Uses (acre-feet/year) 550 800 800 1,925 Sect

100-year Floodplains (incremental acres disturbed) 325 288 0 1,510 Sect

Wilderness Characteristics 

BLM White River Natural Area (incremental acres disturbed) 0 0 0 0 Sect

Non-wilderness Study Area Lands with Wilderness 81 217 139 724 Sect

Characteristics (estimated incremental acres disturbed) 

Wildlife Resources 

Big Game Habitat (estimated incremental acres disturbed) Tab

4.15

Pronghorn Year-long Crucial 3,183 10,264 6,607 34,562 Pronghorn Year-long Substantial 67 179 116 604 Mule Deer Year-long Crucial 553 1,488 958 5,011 

Mule Deer Winter Substantial 68 183 118 615 Elk Winter Substantial 9 24 16 82 Rocky Mountain Bighorn Sheep Year-long Crucial 781 2,103 1,354 7,082 Bison Year-long Crucial Range 3,406 9,168 5,901 30,869 

Potential White-tailed Prairie Dog Habitat (estimated 4,258 11,644 7,581 39,206 Sectincremental acres disturbed) Greater Sage-grouse Habitat (estimated incremental acres Tab

disturbed) 4.15

2.0 Mile Lek Buffer 442 1,190 766 4,007 

Nesting 675 1,817 1,169 6,117 Brooding 1,782 4,797 3,088 16,153 Winter 1,356 3,649 2,349 12,288 

Fisheries Resources 

Estimated total water depletions for life of the project (acre/feet) 2,270 7,571 7,571 27,700 Sect

1 2006 meteorological data show modeled concentrations of ozone between 76 and 79 ppb; 2005 meteorological data show modeled concentrations of ozone below 76 ppb. 2 Modeled deposition from action alternatives does not exceed Federal Managers’ Air Quality Related Values Workgroup thresholds, except for Mesa Verde National Park, which is predict

Action Alternative. 

3 The public sector revenue projections assume constant natural gas prices of $4.59/thousand cubic feet and $45/barrel for liquids. However, energy prices fluctuate over time. Actual secto

lower than shown, depending on future prices and production. Such variance would affect all alternatives. 

DEIS ES-11 
 

Acronyms and Abbreviations 

°F degrees Fahrenheit 

μg/m3 micrograms per cubic meter 

ACEC Area of Critical Environmental Concern 

ACEPM applicant-committed environmental protection measure 

ADT average daily traffic 

AHPA Archaeological and Historical Preservation Act of 1974 

AIRFA American Indian Religious Freedom Act of 1978 

AMP Allotment Management Plan 

amsl above mean sea level 

AO Authorized Officer 

APD Application for Permit to Drill 

API American Petroleum Institute 

APLIC Avian Power Line Interaction Committee 

AQRV Air Quality Related Value 

ARPA Archaeology Resources Protection Act of 1979 

AUM animal unit month 

BA biological assessment 

bbl barrels 

BCC Birds of Conservation Concern 

Bcf billion cubic feet 

BHCA Bird Habitat Conservation Area 

BIA Bureau of Indian Affairs 

BLM Bureau of Land Management 

BMP best management practice 

BSC biological soil crusts 

Btu British thermal unit 

BWPD barrels of water per day 

CAA Clean Air Act 

CAGR Compounded Annual Growth Rate 

CCC Civilian Conservation Corps 

CDOW Colorado Division of Wildlife 

CDP Census Designated Places 

CEQ Council on Environmental Quality 

DEIS AA-1 July 2010 
 

CFR Code of Federal Regulations 

CH4 methane 

CISAs Cumulative Impact Study Areas 

CMAQ Community Multiscale Air Quality 

CO carbon monoxide 

CO2 carbon dioxide 

CO2e carbon dioxide equivalents 

COA Condition of Approval 

CWA Clean Water Act 

dBA decibels on the A-weighted scale 

dv deciview 

DWSPZ drinking water source protection zone 

EA environmental assessment 

EIA Energy Information Administration 

EIS environmental impact statement 

EO Executive Order 

ESA Endangered Species Act 

FEMA Federal Emergency Management Agency 

FLAG Federal Land Managers’ Air Quality Related Values Workgroup 

FLMs Federal Land Managers 

FLPMA Federal Land Policy and Management Act of 1976 

FMR federal mineral royalty 

FOOGLRA Federal Onshore Oil and Gas Leasing Reform Act of 1987 

FY Fiscal Year 

GHG greenhouse gas 

GIS Geographic Information System 

GNBPA Greater Natural Buttes Project Area 

GWP global warming potential 

H2S hydrogen sulfide 

HAP hazardous air pollutant 

hp horsepower 

IC internal combustion 

IPCC Intergovernmental Panel on Climate Change 

kg/ha-year kilograms per hectare-year 

km kilometer 

KMG Kerr-McGee Oil & Gas Onshore LP 

DEIS AA-2 July 2010 
 

KOSLA Known Oil Shale Leasing Areas 

kV kilovolt 

MACT Maximum Achievable Control Technology 

MBTA Migratory Bird Treaty Act 

MCD multi-county district 

Mcf thousand cubic feet 

mg/L milligrams per Liter 

MLA Mineral Leasing Act of 1920 

MMbl million barrels 

MMcfd million cubic feet per day 

mmhos/cm millimhos per centimeter 

N2O nitrous oxide 

NAAQS National Ambient Air Quality Standards 

NAGPRA Native American Graves Protection and Repatriation Act of 1990 

NEPA National Environmental Policy Act 

NHPA National Historic Preservation Act of 1986 

NNSR Non-attainment New Source Review 

NO2 nitrogen dioxide 

NOI Notice of Intent 

NOS Notice of Staking 

NOX oxides of nitrogen 

NPS National Park Service 

NRCS Natural Resource Conservation Service 

NRHP National Register of Historic Places 

NSO No Surface Occupancy 

NSPS New Source Performance Standards 

NWIS National Water Information System 

OHV off-highway vehicle 

OSEC Oil Shale Exploration Company 

PFYC Potential Fossil Yield Classification 

PIF Partners in Flight 

PILT payments-in-lieu of taxes 

PL Public Law 

PM particulate matter 

PM10 particulate matter with an aerodynamic diameter of 10 microns or less 

PM2.5 particulate matter with an aerodynamic diameter of 2.5 microns or less 

DEIS AA-3 July 2010 
PMZ Primary Management Zone 

ppm parts per million 

ppmw parts per million weight 

PSD Prevention of Significant Deterioration 

PWR Public Water Reserve 

RAPPS Reasonable and Prudent Practices for Stabilization 

RDG Resource Development Group 

RFD reasonably foreseeable development 

RIP Recovery and Implementation Program 

RMP Resource Management Plan 

ROD Record of Decision 

ROW right-of-way 

RVs recreational vehicles 

SAAQS State Ambient Air Quality Standards 

SARA Superfund Amendments and Reauthorization Act 

scf standard cubic feet 

SHPO State Historic Preservation Officer 

SI spark-ignition 

SMA surface management agencies 

SO2 sulfur dioxide 

SPCCP Spill Prevention, Control, and Countermeasures Plan 

SR State Road 

SRMA Special Recreation Management Area 

SSA sole source aquifer 

SSD Special Service District 

SSURGO Soil Survey Geographic 

SSXPII Southern System Extension II 

STATSGO General Soil Map 

STSA Special Tar Sand Areas 

SWPPP Storm Water Pollution Prevention Plan 

SWReGAP Southwest Regional Gap Analysis Project 

Tcf trillion cubic feet 

TDS total dissolved solids 

TEG tri-ethylene glycol 

tpy tons per year 

TSS total suspended solids 

DEIS AA-4 July 2010 
UCAT Utah College of Applied Technology 

UDAQ Utah Division of Air Quality 

UDEQ Utah Department of Environmental Quality 

UDNR Utah Department of Natural Resources 

UDOGM Utah Division of Oil, Gas, and Mining 

UDOT Utah Department of Transportation 

UDOWS Utah Department of Workforce Services 

UDWR Utah Division of Wildlife Resources 

UGOPB Utah Governor’s Office of Planning and Budget 

UGS Utah Geologic Survey 

UIC Underground Injection Control 

UNHP Utah Natural Heritage Program 

UNPS Utah Native Plant Society 

UPDES Utah Pollution Discharge Elimination System 

U.S. United States 

USACE U.S. Army Corps of Engineers 

USC United States Code 

USCA United States Code Annotated 

USDA U.S. Department of Agriculture 

USDOE U.S. Department of Energy 

USDOI U.S. Department of the Interior 

USDOT U.S. Department of Transportation 

USDW underground source of drinking water 

USEPA U.S. Environmental Protection Agency 

USFS U.S. Forest Service 

USFWS U.S. Fish and Wildlife Service 

USGS U.S. Geological Survey 

USITLA Utah School and Institutional Trust Lands Administration 

VOC volatile organic compound 

VRM Visual Resource Management 

WIC Wyoming Interstate Company 

WMU wildlife management unit 

WRAP Western Regional Air Partnership 

WSA wilderness study area 

DEIS AA-5 July 2010 
Contents 

Executive Summary ........................................................................................................................................ ES-1
 

Acronyms and Abbreviations ........................................................................................................................AA-1 

1.0 Introduction and Background .................................................................................................................. 1-1
 

1.1 Project Location and Background ....................................................................................................... 1-1
 

1.2 Summary of Proposed Action ............................................................................................................. 1-1
 

1.3 Purpose and Need .............................................................................................................................. 1-4
 

1.4 Environmental Analysis Process ........................................................................................................ 1-4
 

1.4.1 Decisions to be Made After the EIS Process ........................................................................1-5
 

1.5 Legal and Policy Considerations ........................................................................................................ 1-5
 

1.5.1 Leases and Leasing History ..................................................................................................1-5
 

1.5.2 Conformance with BLM Management Plans and Policies ...................................................1-6
 

1.5.3 Consistency with Other Federal and Local Land Management Plans and Policies ............1-6
 

1.5.4 Authorizing Actions and Project Relationships to Statutes and Regulations ......................1-7
 

1.6 Scoping .............................................................................................................................................. 1-10
 

1.6.1 Public Scoping ..................................................................................................................... 1-10
 

1.6.2 Internal Scoping and Issue Identification ............................................................................1-11
 

2.0 Proposed Action and Alternatives .......................................................................................................... 2-1
 

2.1 Greater Natural Buttes Project Area................................................................................................... 2-1
 

2.2 Existing Oil and Gas Infrastructure in the GNBPA.............................................................................2-2
 

2.3 Management Common to All Alternatives .......................................................................................... 2-3
 

2.4 No Action Alternative ........................................................................................................................... 2-6
 

2.4.1 Field Development Plan and Schedule.................................................................................2-7
 

2.4.2 Alternative-specific Activities ................................................................................................. 2-8
 

2.5 Field Development Activities Common to All Action Alternatives ....................................................2-11
 

2.5.1 Pre-construction Activities ...................................................................................................2-12
 

2.5.2 Access Roads ...................................................................................................................... 2-12
 

2.5.3 Drilling and Completion of Vertical Wells ............................................................................2-13
 

2.5.4 Gas Production, Distribution, and Maintenance .................................................................2-16
 

2.5.5 Produced Water Disposal ....................................................................................................2-18
 

2.5.6 Hazardous Materials and Solid Waste ................................................................................2-19
 

2.5.7 Reclamation and Abandonment ..........................................................................................2-20
 

2.6 Proposed Action Alternative..............................................................................................................2-20
 

2.6.1 Field Development Plan and Schedule...............................................................................2-21
 

2.6.2 Alternative-specific Activities ...............................................................................................2-22
 

DEIS July 2010 i 
2.7 Resource Protection Alternative ....................................................................................................... 2-25
 

2.7.1 Field Development Plan and Schedule...............................................................................2-26
 

2.7.2 Alternative-specific Activities ...............................................................................................2-27
 

2.8 Optimal Recovery Alternative ........................................................................................................... 2-29
 

2.8.1 Field Development Plan and Schedule...............................................................................2-30
 

2.8.2 Alternative-specific Activities ...............................................................................................2-32
 

2.9 Alternatives Considered but Eliminated from Further Consideration ..............................................2-33
 

2.10 Comparison of Alternatives ............................................................................................................... 2-34
 

3.0 Affected Environment ............................................................................................................................... 3-1
 

3.1 Air Quality ............................................................................................................................................ 3-2
 

3.1.1 Regional Climate ................................................................................................................... 3-2
 

3.1.2 Air Quality............................................................................................................................... 3-3
 

3.1.3 Regulatory Framework ..........................................................................................................3-5
 

3.2 Cultural Resources and Native American Traditional Values ..........................................................3-12
 

3.2.1 Cultural Resources .............................................................................................................. 3-12
 

3.2.2 Native American Traditional Values ....................................................................................3-19
 

3.3 Geology ............................................................................................................................................. 3-22
 

3.3.1 Mineral Resources ............................................................................................................... 3-22
 

3.4 Land Use ........................................................................................................................................... 3-28
 

3.4.1 White River Special Recreation Management Area...........................................................3-28
 

3.5 Paleontology ...................................................................................................................................... 3-32
 

3.6 Range Resources..............................................................................................................................3-36
 

3.7 Recreation ......................................................................................................................................... 3-40
 

3.8 Socioeconomics and Environmental Justice ....................................................................................3-43
 

3.8.1 Study Area for Socioeconomics ..........................................................................................3-43
 

3.8.2 Background on the Role of Oil and Gas Development in the Region ...............................3-43
 

3.8.3 Local Population .................................................................................................................. 3-44
 

3.8.4 Local Economy and Labor Force ........................................................................................3-47
 

3.8.5 Specific Economic Sectors..................................................................................................3-52
 

3.8.6 Community Facilities and Services .....................................................................................3-55
 

3.8.7 Public Expenditures and Revenues ....................................................................................3-60
 

3.8.8 Population and Employment Projections ............................................................................3-65
 

3.8.9 Community Social Conditions .............................................................................................3-65
 

3.8.10 Environmental Justice .........................................................................................................3-68
 

3.9 Soils ................................................................................................................................................... 3-70
 

3.9.1 Soils Characterization .......................................................................................................... 3-70
 

3.9.2 Soil Constraints .................................................................................................................... 3-70
 

3.9.3 Biological Soil Crusts........................................................................................................... 3-73
 

3.10 Transportation and Access ............................................................................................................... 3-74
 

3.11 Vegetation Resources ....................................................................................................................... 3-76
 

3.11.1 General Vegetation .............................................................................................................. 3-76
 

DEIS July 2010 ii 
3.11.2	 Noxious Weeds and Invasive Species................................................................................3-79
 

3.11.3	 Special Status Plant Species ..............................................................................................3-81
 

3.12 Visual Resources .............................................................................................................................. 3-86
 

3.12.1	 Visual Resource Management Classification .....................................................................3-86
 

3.13 Water Resources ............................................................................................................................... 3-90
 

3.13.1	 Surface Water ...................................................................................................................... 3-90
 

3.13.2	 Floodplains, Waters of the U.S., and Wetlands ..................................................................3-97
 

3.13.3	 Groundwater Resources ...................................................................................................3-102
 

3.14 Wilderness Characteristics ............................................................................................................. 3-107
 

3.14.1	 BLM White River Natural Area ..........................................................................................3-107
 

3.14.2	 Non-WSA Lands with Wilderness Characteristics ............................................................3-107
 

3.15 Wildlife and Fisheries Resources ................................................................................................... 3-110
 

3.15.1	 Wildlife ................................................................................................................................ 3-110
 

3.15.2	 Fisheries Resources ..........................................................................................................3-126
 

4.0 Environmental Impacts ............................................................................................................................. 4-1
 

4.1 Air Quality ............................................................................................................................................ 4-2
 

4.1.1	 No Action Alternative ............................................................................................................. 4-6
 

4.1.2	 Proposed Action Alternative ..................................................................................................4-8
 

4.1.3	 Resource Protection Alternative..........................................................................................4-12
 

4.1.4	 Optimal Recovery Alternative ..............................................................................................4-13
 

4.1.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-17
 

4.1.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-17
 

4.2 Cultural Resources and Native American Traditional Values ..........................................................4-18
 

4.2.1	 No Action Alternative ........................................................................................................... 4-18
 

4.2.2	 Proposed Action Alternative ................................................................................................4-18
 

4.2.3	 Resource Protection Alternative..........................................................................................4-21
 

4.2.4	 Optimal Recovery Alternative ..............................................................................................4-21
 

4.2.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-21
 

4.2.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-22
 

4.3 Geology ............................................................................................................................................. 4-23
 

4.3.1	 No Action Alternative ........................................................................................................... 4-23
 

4.3.2	 Proposed Action Alternative ................................................................................................4-23
 

4.3.3	 Resource Protection Alternative..........................................................................................4-24
 

4.3.4	 Optimal Recovery Alternative ..............................................................................................4-25
 

4.3.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-26
 

4.3.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-26
 

4.4 Land Use ........................................................................................................................................... 4-27
 

4.4.1	 No Action Alternative ........................................................................................................... 4-27
 

4.4.2	 Proposed Action Alternative ................................................................................................4-27
 

4.4.3	 Resource Protection Alternative..........................................................................................4-28
 

DEIS	 July 2010 iii 
4.4.4	 Optimal Recovery Alternative ..............................................................................................4-29
 

4.4.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-30
 

4.4.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-30
 

4.5 Paleontology ...................................................................................................................................... 4-31
 

4.5.1	 No Action Alternative ........................................................................................................... 4-31
 

4.5.2	 Proposed Action Alternative ................................................................................................4-31
 

4.5.3	 Resource Protection Alternative..........................................................................................4-32
 

4.5.4	 Optimal Recovery Alternative ..............................................................................................4-32
 

4.5.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-32
 

4.5.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-32
 

4.6 Range Resources..............................................................................................................................4-33
 

4.6.1	 No Action Alternative ........................................................................................................... 4-33
 

4.6.2	 Proposed Action Alternative ................................................................................................4-34
 

4.6.3	 Resource Protection Alternative..........................................................................................4-39
 

4.6.4	 Optimal Recovery Alternative ..............................................................................................4-41
 

4.6.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-44
 

4.6.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-44
 

4.7 Recreation ......................................................................................................................................... 4-45
 

4.7.1	 No Action Alternative ........................................................................................................... 4-45
 

4.7.2	 Proposed Action Alternative ................................................................................................4-45
 

4.7.3	 Resource Protection Alternative..........................................................................................4-46
 

4.7.4	 Optimal Recovery Alternative ..............................................................................................4-46
 

4.7.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-47
 

4.7.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-47
 

4.8 Socioeconomics and Environmental Justice ....................................................................................4-48
 

4.8.1	 No Action Alternative ........................................................................................................... 4-53
 

4.8.2	 Proposed Action Alternative ................................................................................................4-60
 

4.8.3	 Resource Protection Alternative..........................................................................................4-69
 

4.8.4	 Optimal Recovery Alternative ..............................................................................................4-69
 

4.8.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-75
 

4.8.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-76
 

4.9 Soils ................................................................................................................................................... 4-77
 

4.9.1	 No Action Alternative ........................................................................................................... 4-79
 

4.9.2	 Proposed Action Alternative ................................................................................................4-81
 

4.9.3	 Resource Protection Alternative..........................................................................................4-83
 

4.9.4	 Optimal Recovery Alternative ..............................................................................................4-84
 

4.9.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-85
 

4.9.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-85
 

DEIS	 July 2010 iv 
4.10 Transportation and Access ............................................................................................................... 4-86
 

4.10.1 No Action Alternative ........................................................................................................... 4-86
 

4.10.2 Proposed Action Alternative ................................................................................................4-86
 

4.10.3	 Resource Protection Alternative..........................................................................................4-88
 

4.10.4	 Optimal Recovery Alternative ..............................................................................................4-88
 

4.10.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity ...............................................4-89
 

4.10.6	 Irreversible/Irretrievable Commitment of Resources ..........................................................4-89
 

4.11 Vegetation.......................................................................................................................................... 4-90
 

4.11.1 No Action Alternative ........................................................................................................... 4-90
 

4.11.2 Proposed Action Alternative ................................................................................................4-94
 

4.11.3	 Resource Protection Alternative........................................................................................4-102
 

4.11.4	 Optimal Recovery Alternative ............................................................................................4-103
 

4.11.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity .............................................4-104
 

4.11.6	 Irreversible/Irretrievable Commitment of Resources ........................................................4-104
 

4.12 Visual Resources ............................................................................................................................ 4-106
 

4.12.1 No Action Alternative .........................................................................................................4-106
 

4.12.2 Proposed Action Alternative ..............................................................................................4-106
 

4.12.3	 Resource Protection Alternative........................................................................................4-108
 

4.12.4	 Optimal Recovery Alternative ............................................................................................4-109
 

4.12.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity .............................................4-110
 

4.12.6	 Irreversible/Irretrievable Commitment of Resources ........................................................4-110
 

4.13 Water Resources ............................................................................................................................. 4-111
 

4.13.1 No Action Alternative .........................................................................................................4-112
 

4.13.2 Proposed Action Alternative ..............................................................................................4-119
 

4.13.3	 Resource Protection Alternative........................................................................................4-125
 

4.13.4	 Optimal Recovery Alternative ............................................................................................4-127
 

4.13.5	 Relationship between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity .............................................4-130
 

4.13.6	 Irreversible/Irretrievable Commitment of Resources ........................................................4-130
 

4.14 Wilderness Characteristics ............................................................................................................. 4-131
 

4.14.1 No Action Alternative .........................................................................................................4-131
 

4.14.2 Proposed Action Alternative ..............................................................................................4-131
 

4.14.3	 Resource Protection Alternative........................................................................................4-132
 

4.14.4	 Optimal Recovery Alternative ............................................................................................4-133
 

4.14.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of Long-term Productivity .............................................4-134
 

4.14.6	 Irreversible/Irretrievable Commitment of Resources ........................................................4-134
 

4.15 Wildlife and Fisheries Resources ................................................................................................... 4-135
 

4.15.1 No Action Alternative .........................................................................................................4-135
 

4.15.2 Proposed Action Alternative ..............................................................................................4-145
 

4.15.3 Resource Protection Alternative........................................................................................4-153
 

4.15.4 Optimal Recovery Alternative ............................................................................................4-159
 

DEIS	 v July 2010 
4.15.5	 Relationship Between Local Short-term Uses of the Human Environment and 

Maintenance and Enhancement of the Long-term Productivity .......................................4-165
 

4.15.6	 Irreversible/Irretrievable Commitment of Resources ........................................................4-165
 

5.0 Cumulative Impacts ................................................................................................................................... 5-1
 

5.1 Time Frame ......................................................................................................................................... 5-1
 

5.2 Past, Present, and Reasonably Foreseeable Future Projects ..........................................................5-1
 

5.2.1	 Oil and Gas ............................................................................................................................ 5-1
 

5.2.2	 Oil Shale............................................................................................................................... 5-11
 

5.2.3	 Gilsonite ............................................................................................................................... 5-11
 

5.2.4	 Tar Sands.............................................................................................................................5-12
 

5.2.5	 Sand and Gravel .................................................................................................................. 5-12
 

5.2.6	 Other Activities..................................................................................................................... 5-12
 

5.3 Cumulative Impacts by Resource ..................................................................................................... 5-13
 

5.3.1	 Air Quality............................................................................................................................. 5-13
 

5.3.2	 Cultural Resources and Native American Traditional Values ............................................5-15
 

5.3.3	 Geology ................................................................................................................................ 5-16
 

5.3.4	 Land Use .............................................................................................................................. 5-16
 

5.3.5	 Paleontology ........................................................................................................................ 5-16
 

5.3.6	 Range Resources ................................................................................................................ 5-17
 

5.3.7	 Recreation ............................................................................................................................ 5-22
 

5.3.8	 Socioeconomics ................................................................................................................... 5-22
 

5.3.9	 Soils ...................................................................................................................................... 5-25
 

5.3.10	 Transportation ...................................................................................................................... 5-26
 

5.3.11	 Vegetation ............................................................................................................................ 5-26
 

5.3.12	 Visual Resources ................................................................................................................. 5-29
 

5.3.13	 Water Resources ................................................................................................................. 5-30
 

5.3.14	 Wilderness Characteristics ..................................................................................................5-33
 

5.3.15	 Wildlife and Fisheries Resources ........................................................................................5-34
 

6.0 Consultation and Coordination................................................................................................................6-1
 

6.1 Agency Participation/Coordination...................................................................................................... 6-1
 

6.2 Public Involvement .............................................................................................................................. 6-8
 

6.3 List of Preparers and Reviewers .........................................................................................................6-9
 

7.0 Glossary ...................................................................................................................................................... 7-1
 

8.0 References .................................................................................................................................................. 8-1
 

9.0 Index ............................................................................................................................................................ 9-1
 

DEIS	 July 2010 vi 
 

List of Appendices 

Appendix A – Applicant-Committed Environmental Protection Measures 

Appendix B – Interdisciplinary Team Analysis Record Checklist 

Appendix C – Transportation Plan 

Appendix D – Example Spill Prevention Control and Countermeasures Plan 

Appendix E – Reclamation Plan 

Appendix F – Soil Mapping Data 

Appendix G – Air Quality Technical Support Document 

Appendix H – Special Status Species List 

Appendix I – Migratory Bird Species List 

Appendix J – Integrated Weed Management Plan 

Appendix K – Range Improvement Specifications and Design Drawings 

Appendix L – BLM and USFWS Clay Reed-mustard and Uinta Basin Hookless Cactus Conservation Measures 

Appendix M – Graham’s Beardtongue Conservation Measures 

DEIS July 2010 vii 
List of Tables 

Table 1.5-1 Key Federal, State, and Local Permits, Approvals, and Authorizing Actions for 

Construction, Operation, Maintenance, and Abandonment of the Proposed Action .................1-8
 

Table 2.1-1 Surface and Oil and Gas Minerals Ownership within the GNBPA .............................................2-2
 

Table 2.2-1 Existing Facilities .......................................................................................................................... 2-2
 

Table 2.3-1 Key Oil and Gas Development and Production Guidelines Applicable to all Alternatives.........2-3
 

Table 2.4-1 No Action Alternative Summary of New Surface Disturbance ....................................................2-6
 

Table 2.6-1 Proposed Action Alternative Summary of New Surface Disturbance .......................................2-20
 

Table 2.7-1 Resource Protection Alternative Summary of New Surface Disturbance ................................2-25
 

Table 2.8-1 Optimal Recovery Alternative Summary of New Surface Disturbance ....................................2-29
 

Table 2.10-1 Disturbance Comparison for GNBPA Alternatives (Excluding Existing Condition) ..................2-35
 

Table 2.10-2 Impact Comparison by Resource for All Alternatives ................................................................2-36
 

Table 3.1-1 Monthly Climate Summary for Vernal Airport, Utah ....................................................................3-2
 

Table 3.1-2 Ambient Air Quality Background Values ......................................................................................3-3
 

Table 3.1-3 National Ambient Air Quality Standards ......................................................................................3-6
 

Table 3.1-4 Class I and Sensitive Class II Areas of Concern for Air Quality Impact Analysis ......................3-6
 

Table 3.1-5 PSD Increments for Class I and Class II Areas ...........................................................................3-7
 

Table 3.2-1 Prehistoric Site Types and Cultural Affiliations ..........................................................................3-16
 

Table 3.2-2 Historic Site Types and Cultural Affiliations ...............................................................................3-17
 

Table 3.2-3 Multicomponent Site Types and Cultural Affiliations.................................................................3-18
 

Table 3.2-4 Site Eligibility and Land Status ................................................................................................... 3-19
 

Table 3.3-1 Cumulative Production in the GNBPA by Producing Zone 1984 – 2006 .................................3-25
 

Table 3.5-1 Identified Paleontological Resources of the Uinta Formation in the GNBPA ...........................3-33
 

Table 3.6-1 Grazing Allotments Within the GNBPA ......................................................................................3-37
 

Table 3.6-2 Range Improvements within the GNBPA ..................................................................................3-39
 

Table 3.7-1 Mule Deer Hunting Statistics...................................................................................................... 3-40
 

Table 3.7-2 Elk Hunting Statistics .................................................................................................................. 3-41
 

Table 3.8-1 Oil and Gas Development Summary, 2005 to 2008 .................................................................3-43
 

Table 3.8-2 County Population Trends .......................................................................................................... 3-45
 

Table 3.8-3 Population Growth Trends within Each County .........................................................................3-45
 

Table 3.8-4 Racial Demographics by Community ........................................................................................3-46
 

Table 3.8-5 Components of Population Change ...........................................................................................3-46
 

Table 3.8-6 Resident Population on the Uintah and Ouray Reservation .....................................................3-47
 

Table 3.8-7 Composition of Total Employment in the Study Area ...............................................................3-48
 

Table 3.8-8 Non-Farm Wage and Salary Employment by Major Industry, 2007 .........................................3-48
 

Table 3.8-9 Labor Force and Unemployment Rates .....................................................................................3-50
 

DEIS July 2010 viii 
Table 3.8-10 Per Capita Personal Income ...................................................................................................... 3-51
 

Table 3.8-11 Private Non-Farm Average Monthly Wages, by Major Industry, 2006 .....................................3-51
 

Table 3.8-12 Composition of Total Personal Income, 2005 ...........................................................................3-52
 

Table 3.8-13 Workforce Commuting in Duchesne and Uintah Counties, 2000.............................................3-52
 

Table 3.8-14 Approximate Value of Annual Livestock Production from Federal Grazing Leases ................3-53
 

Table 3.8-15 Oil and Gas Development Related Businesses in the GNBPA, 2006 ......................................3-55
 

Table 3.8-16 County Housing Stock By Type, 2000 .......................................................................................3-56
 

Table 3.8-17 Total Housing Units by County .................................................................................................. 3-56
 

Table 3.8-18 Cumulative Building Permits for New Residential Development ..............................................3-56
 

Table 3.8-19 Homes Sales and Average Prices in the Uinta Basin ...............................................................3-57
 

Table 3.8-20 Selected Characteristic, Duchesne County and Uintah School Districts .................................3-59
 

Table 3.8-21 Total County Expenditures by Use, in Millions ..........................................................................3-60
 

Table 3.8-22 Total Revenue for County Government, in Millions ...................................................................3-60
 

Table 3.8-23 Total City Expenditures by Use, in Millions ...............................................................................3-61
 

Table 3.8-24 Total Revenue for City Government, in Millions........................................................................3-61
 

Table 3.8-25 Total Public School District Expenditures by Use, in Millions ...................................................3-62
 

Table 3.8-26 Total Revenues for Public School Districts, in Millions .............................................................3-62
 

Table 3.8-27 Ad Valorem Tax Base of Local Governments, 2006 (In Millions) .............................................3-63
 

Table 3.8-28 Mineral Lease Distributions to Duchesne and Uintah Counties from UDOT 

Appropriation, in Millions ............................................................................................................ 3-64
 

Table 3.8-29 Utah Permanent Community Impact Fund Grant and Loan Funding, Fiscal 

Years 2001 to 2005 .................................................................................................................... 3-64
 

Table 3.8-30 Population Projections to 2040 .................................................................................................. 3-65
 

Table 3.8-31 Employment Projections to 2040 ...............................................................................................3-65
 

Table 3.8-32 Poverty and Minority Population Characteristics of Selected Communities, 2000 ..................3-68
 

Table 3.10-1 BLM Road Types within the GNBPA .........................................................................................3-74
 

Table 3.10-2 Traffic Density for Project Region .............................................................................................. 3-74
 

Table 3.11-1 Vegetation Cover Types within the GNBPA ..............................................................................3-76
 

Table 3.11-2 Designated Noxious Weeds and Invasive Species Potentially Occurring 

Within the GNBPA...................................................................................................................... 3-80
 

Table 3.13-1 Drainage Areas of Selected Streams ........................................................................................3-90
 

Table 3.13-2 Precipitation-Frequency-Duration Values for the Study Area ...................................................3-91
 

Table 3.13-3 Mean Annual Peak Flow for Smaller Streams, Cubic Feet per Second...................................3-93
 

Table 3.13-4 Estimated Flood Flows for Smaller Streams, Cubic Feet per Second .....................................3-93
 

Table 3.13-5 Beneficial Use Designations for Surface Waters ......................................................................3-94
 

Table 3.15-1 Greater Sage-grouse Lek Counts (males only) from 1999-2009 ...........................................3-123
 

Table 4.1-1 Summary of Criteria Pollutant Emissions for Each Scenario ......................................................4-3
 

DEIS July 2010 ix 
Table 4.1-2 Summary of Potential Increases in Emissions of HAPs for Project-related Alternatives...........4-3
 

Table 4.1-3 Summary of Emissions Calculation Methods by Source Type and Pollutant ............................4-4
 

Table 4.1-4 Air Quality Impacts for Criteria Air Pollutants in the Near-field, No Action Alternative...............4-6
 

Table 4.1-5 Detailed Summary of Annual GHG Emissions by Source for the No Action Alternative...........4-8
 

Table 4.1-6 CALPUFF Modeled Results for Acid Deposition, Proposed Action............................................4-9
 

Table 4.1-7 CALPUFF Modeled Results for Regional Haze, Proposed Action...........................................4-10
 

Table 4.1-8 Detailed Summary of GHG Emissions by Source for the Proposed Action Alternative ..........4-11
 

Table 4.1-9 CALPUFF Modeled Results for Acid Deposition, Optimal Recovery Alternative .....................4-14
 

Table 4.1-10 CALPUFF Modeled Results for Regional Haze, Optimal Recovery Alternative ......................4-15
 

Table 4.1-11 Detailed Summary of GHG Emissions by Source for the Optimal Recovery Alternative ........4-16
 

Table 4.4-1 Summary of Surface Ownership Impacts for Each Alternative.................................................4-27
 

Table 4.6-1 Carrying Capacity Impacts by Allotment Under the No Action Alternative ...............................4-33
 

Table 4.6-2 Carrying Capacity Impacts by Allotment Under the Proposed Action ......................................4-34
 

Table 4.6-3 Range Improvements Potentially Impacted Under the Proposed Action .................................4-37
 

Table 4.6-4 Carrying Capacity Impacts by Allotment Under the Resource Protection Alternative .............4-40
 

Table 4.6-5 Range Improvements Impacted Under the Resource Protection Alternative ..........................4-41
 

Table 4.6-6 Carrying Capacity Impacts by Allotment Under the Optimal Recovery Alternative .................4-42
 

Table 4.6-7 Range Improvements Impacted Under the Optimal Recovery Alternative ..............................4-43
 

Table 4.8-1 Projected New Wells and Total Projected Natural Gas and Oil Condensate Production........4-49
 

Table 4.8-2 Project Spending Assumptions, All Alternatives........................................................................4-49
 

Table 4.8-3 Geographical Distribution of Spending by Activity, All Alternatives ..........................................4-50
 

Table 4.8-4 Assumed Geographic Distribution of Project-related Employment, Population,
 

and Housing Growth, All Alternatives ........................................................................................4-51
 

Table 4.8-5 Employment and Income Impacts, No Action Alternative.........................................................4-55
 

Table 4.8-6 Average Population and Housing Demand Impacts, No Action Alternative.............................4-56
 

Table 4.8-7 Local Government General Purpose Cost During Development (2006 $), 

No Action Alternative .................................................................................................................. 4-57
 

Table 4.8-8 Selected Major Public Revenues Over the Life of Field, No Action Alternative .......................4-58
 

Table 4.8-9 Project-related Employment and Income, Proposed Action Alternative ...................................4-62
 

Table 4.8-10 Project-related Population and Housing Demand, Proposed Action Alternative .....................4-63
 

Table 4.8-11 Local Government General Purpose Cost During Development (2006 $), Proposed 

Action Alternative ........................................................................................................................ 4-66
 

Table 4.8-12 Selected Major Public Revenues Over the Life of Field, Proposed Action Alternative............4-66
 

Table 4.8-13 Project-related Employment and Income, Optimal Recovery Alternative ................................4-71
 

Table 4.8-14 Project-related Population and Housing Demand, Optimal Recovery Alternative...................4-72
 

Table 4.8-15 Local Government General Purpose Cost During Development (2006 $), 

Optimal Recovery Alternative..................................................................................................... 4-73
 

DEIS x July 2010 
Table 4.8-16 Selected Major Public Revenues Over the Life of Field, Optimal Recovery Alternative..........4-74
 

Table 4.9-1 Anticipated Acreage Disturbance for High, Moderate, and Low Constraint 

Soils by Alternative ..................................................................................................................... 4-78
 

Table 4.10-1 Anticipated Vehicle Activity for GNBPA, Proposed Action Alternative .....................................4-87
 

Table 4.11-1 Acreages of Affected Vegetation Under the No Action Alternative ..........................................4-90
 

Table 4.11-2 Acreages of Affected Vegetation under the Proposed Action Alternative ................................4-94
 

Table 4.11-3 Acreages of Affected Vegetation Under the Resource Protection Alternative .......................4-102
 

Table 4.11-4 Acreages of Affected Vegetation Under the Optimal Recovery Alternative ...........................4-103
 

Table 4.13-1 New and Existing Surface Disturbance in Major Watersheds, No Action Alternative............4-113
 

Table 4.13-2 Previously Authorized and New Surface Disturbance in Major Watersheds, 

Proposed Action Alternative ..................................................................................................... 4-119
 

Table 4.13-3 Previously Authorized and New Surface Disturbance in Major Watersheds, 

Resource Protective Alternative...............................................................................................4-126
 

Table 4.13-4 Previously Authorized and New Surface Disturbance in Major Watersheds, 

Optimal Recovery Alternative...................................................................................................4-128
 

Table 4.15-1 Long-term Surface Disturbance of Big Game Habitat, No Action Alternative ........................4-136
 

Table 4.15-2 Long-term Surface Disturbance of Greater Sage-grouse Habitat, No Action
 

Alternative ................................................................................................................................. 4-142
 

Table 4.15-3 Long-term Surface Disturbance of Big Game Habitat, Proposed Action ...............................4-146
 

Table 4.15-4 Long-term Surface Disturbance of Greater Sage-grouse Habitat, Proposed Action .............4-150
 

Table 4.15-5 Long-term Surface Disturbance of Big Game Habitat, Resource Protection 

Alternative ................................................................................................................................. 4-154
 

Table 4.15-6 Long-term Surface Disturbance of Greater Sage-grouse Habitat, Resource Protection
 

Alternative ................................................................................................................................. 4-156
 

Table 4.15-7 Long-term Surface Disturbance of Big Game Habitat, Optimal Recovery Alternative ...........4-160
 

Table 4.15-8 Long-term Surface Disturbance of Greater Sage-grouse Habitat, Optimal 

Recovery Alternative ................................................................................................................ 4-162
 

Table 5.2-1 Cumulative Impact Study Areas for the Greater Natural Buttes EIS..........................................5-2
 

Table 5.2-2 Surface Disturbance Estimates for Past and Present Projects in the General 

Cumulative Effects Area............................................................................................................... 5-9
 

Table 5.2-3 Surface Disturbance Estimates for Reasonably Foreseeable Projects in the 

General Cumulative Effects Area.................................................................................................5-9
 

Table 5.2-4 Permitted Gilsonite Mines, Uinta Basin ..................................................................................... 5-12
 

Table 5.3-1 Summary of Emissions from Oil and Gas Operations in Uinta Basin – 2006 ..........................5-13
 

Table 5.3-2 Cumulative Impacts Compared to NAAQS ............................................................................... 5-13
 

Table 5.3-3 Cumulative Carrying Capacity Impacts per Allotment for the Proposed Action 

Alternative ................................................................................................................................... 5-18
 

Table 5.3-4 Cumulative Carrying Capacity Impacts per Allotment for the Resource Recovery 

Alternative ................................................................................................................................... 5-19
 

DEIS July 2010 xi 
Table 5.3-5 Cumulative Carrying Capacity Impacts per Allotment for the Optimal Recovery 

Alternative ................................................................................................................................... 5-20
 

Table 5.3-6 Cumulative Estimated Surface Disturbance of Uinta Basin Hookless Cactus Habitat ............5-29
 

Table 5.3-7 Summary of Impaired Waterbodies Within the CISA ................................................................5-31
 

Table 5.3-8 Cumulative Long-term Surface Disturbance of Big Game Habitat ...........................................5-41
 

Table 5.3-9 Cumulative Long-term Surface Disturbance of Greater Sage-grouse Habitat .........................5-43
 

Table 6.1-1 Status of Section 7 and Section 106 Consultation ......................................................................6-3
 

Table 6.3-1 BLM Interdisciplinary Team..........................................................................................................6-9
 

Table 6.3-2 Preparers/Reviewers for AECOM and Subcontractors .............................................................6-10
 

DEIS July 2010 xii 
List of Figures 

Figure 1.1-1 Regional Location Map............................................................................................................... 1-2
 

Figure 1.1-2 Oil and Gas Fields ...................................................................................................................... 1-3
 

Figure 2.4-1 No Action Alternative .................................................................................................................. 2-9
 

Figure 2.4-2 Existing Access Roads ............................................................................................................. 2-10
 

Figure 2.6-1 Proposed Action ........................................................................................................................ 2-23
 

Figure 2.7-1 Resource Protection Alternative...............................................................................................2-28
 

Figure 2.8-1 Optimal Recovery Alternative................................................................................................... 2-31
 

Figure 3.1-1 Wind Rose from Vernal, Utah, Airport ........................................................................................3-4
 

Figure 3.3-1 Uinta-Piceance Basin ............................................................................................................... 3-23
 

Figure 3.3-2 Surface Geology Stratigraphic Column ....................................................................................3-24
 

Figure 3.3-3 Natural Buttes Gas Production 1984 to 2006 ..........................................................................3-25
 

Figure 3.4-1 Land Cover Types .....................................................................................................................3-29
 

Figure 3.4-2 Land Ownership ........................................................................................................................ 3-30
 

Figure 3.4-3 Areas of Special Designation ................................................................................................... 3-31
 

Figure 3.5-1 Paleological Sensitivity ............................................................................................................. 3-35
 

Figure 3.6-1 Grazing Allotments and Range Improvements ........................................................................3-38
 

Figure 3.7-1 Recreation Areas ...................................................................................................................... 3-42
 

Figure 3.8-1 Total Full and Part-time Employment, 1970 to 2007 ...............................................................3-47
 

Figure 3.9-1 Soil Constraints ......................................................................................................................... 3-72
 

Figure 3.10-1 Transportation Network and Transportation / Utility Corridors ................................................3-75
 

Figure 3.11-1 Vegetation Cover Types ........................................................................................................... 3-78
 

Figure 3.12-1 Visual Resource Management Classes ...................................................................................3-88
 

Figure 3.12-2 Visibility from White River and Goblin City Overlook ...............................................................3-89
 

Figure 3.13-1 Major Watersheds ..................................................................................................................... 3-92
 

Figure 3.13-2 Estimated Sediment Yields ....................................................................................................... 3-95
 

Figure 3.13-3 Hundred-year Floodplains and Public Water Reserves ........................................................3-100
 

Figure 3.13-4 Riparian Areas ........................................................................................................................ 3-101
 

Figure 3.13-5 General Stratigraphy and Water Bearing Units .....................................................................3-103
 

Figure 3.13-6 Groundwater Source Protection Zones ..................................................................................3-106
 

Figure 3.14-1 Non-WSA Lands with Wilderness Characteristics, BLM Natural Areas, and SRMAs..........3-109
 

Figure 3.15-1 Pronghorn Habitat ................................................................................................................... 3-112
 

Figure 3.15-2 Mule Deer Habitat ................................................................................................................... 3-113
 

Figure 3.15-3 Elk Habitat ............................................................................................................................... 3-114
 

Figure 3.15-4 Rocky Mountain Bighorn Sheep Habitat ................................................................................3-115
 

DEIS July 2010 xiii 
Figure 3.15-5 Bison Habitat ........................................................................................................................... 3-116
 

Figure 3.15-6 White-tailed Prairie Dog Colonies ..........................................................................................3-119
 

Figure 3.15-7 Greater Sage-grouse Habitat .................................................................................................3-124
 

Figure 4.8-1 Projected Natural Gas Production for the Project Alternatives ...............................................4-48
 

Figure 4.8-2 Direct On-Site Employment to Develop a Typical Well ...........................................................4-50
 

Figure 4.8-3 Historical and Projected Wellhead Prices for Natural Gas ......................................................4-52
 

Figure 4.8-4 Direct Project Spending Under the No Action Alternative .......................................................4-54
 

Figure 4.8-5 Market Value of Product Sold, No Action Alternative ..............................................................4-54
 

Figure 4.8-6 Direct Project Spending, Proposed Action Alternative ............................................................4-61
 

Figure 4.8-7 Annual Sales Value of Production, Proposed Action Alternative ............................................4-61
 

Figure 4.8-8 Project Direct Spending, Optimal Recovery Alternative ..........................................................4-70
 

Figure 4.8-9 Annual Sales Value of Production, Optimal Recovery Alternative ..........................................4-70
 

Figure 4.8-10 Total Employment in the Study Area, Optimal Recovery Alternative......................................4-71
 

Figure 5.2-1 Reasonably Foreseeable Development Areas ..........................................................................5-5
 

Figure 5.2-2 Cumulative Actions Oil and Gas Field Development .................................................................5-6
 

Figure 5.2-3 Cumulative Actions Seismic and Pipeline Projects ...................................................................5-7
 

Figure 5.2-4 Cumulative Actions Oil and Gas Field Development and Pipeline Projects.............................5-8
 

Figure 5.3-1 Grazing Allotments Cumulative Impacts Study Area...............................................................5-21
 

Figure 5.3-2 Projected Natural Gas Production in the Mountain Region .....................................................5-23
 

Figure 5.3-3 Projected Resident Population of Uintah and Duchesne Counties to 2035 ...........................5-24
 

Figure 5.3-4 Water Resources CISA and Cumulative Actions Location Map .............................................5-32
 

Figure 5.3-5 Cumulative Actions Wilderness Characteristics ......................................................................5-35
 

Figure 5.3-6 Cumulative Actions Pronghorn Habitat ....................................................................................5-36
 

Figure 5.3-7 Cumulative Actions Mule Deer Habitat ....................................................................................5-37
 

Figure 5.3-8 Cumulative Actions Elk Habitat ................................................................................................5-38
 

Figure 5.3-9 Cumulative Actions Rocky Mountain Bighorn Sheep Habitat .................................................5-39
 

Figure 5.3-10 Cumulative Actions Bison Habitat ............................................................................................5-40
 

Figure 5.3-11 Cumulative Actions Greater Sage-grouse Habitat ...................................................................5-45
 

DEIS July 2010 xiv 
 

 

 

 

 

 

1.0 Introduction and Background 

1.1 Project Location and Background 

Kerr-McGee Oil & Gas Onshore LP (KMG), a wholly owned subsidiary of Anadarko Petroleum Corporation, 

has notified the Bureau of Land Management’s (BLM) Vernal Field Office that it proposes to conduct infill 

drilling to develop the hydrocarbon resources from oil and gas leases owned, at least in part, by KMG within 

the Greater Natural Buttes Project Area (GNBPA) in Uintah County, Utah (Figure 1.1-1). KMG intends to 

explore and develop all potentially productive subsurface formations underlying the GNBPA. The formations 

include, but are not limited to, the Green River Formation, Wasatch Formation, Mesaverde Group (including 

the Blackhawk Formation), Mancos Shale, and Dakota Sandstone. KMG owns contractual leasehold rights for 

more than 85 percent of the lands within the GNBPA. In most cases, KMG’s lease rights include the right to 

occupy the surface to explore, develop, operate, and produce the subsurface oil and gas resources. 

The GNBPA consists of approximately 162,911 acres in an existing gas producing region (Township 8 South, 

Range 20-23 East; T9S, R20-24E; T10S, R20-23E; and T11S, R21-22E) located on lands owned by the 

federal government, the State of Utah, the Ute Tribe, and other private land owners. The GNBPA includes 

portions of at least nine oil and gas fields, most of which are included in the larger Natural Buttes Field, 

currently the most productive gas field in Utah (Figure 1.1-2). The oil and gas fields located within the GNBPA 

are the Devil’s Playground Field, the Love Field, the Natural Buttes Field, the Southman Canyon Field, the 

Uintah Field, the Chapita Wells Field, the Bitter Creek Field, the Ouray Field, and the Stagecoach Field. 

Federal lands in the proposed GNBPA are under the jurisdiction of the BLM Vernal Field Office. The Vernal 

Field Office has determined that the proposed project constitutes a major federal action requiring the 

development of an environmental impact statement (EIS). This EIS serves the purpose of disclosing and 

analyzing impacts resulting from the level of development proposed within the GNBPA, including a no action 

alternative, with consideration of identified and applied applicant-committed environmental protection 

measures (ACEPMs), the BLM best management practices (BMPs), and identified mitigation measures. A 

summary of these ACEPMs is provided in Appendix A. 

1.2 Summary of Proposed Action 

KMG’s proposed infill drilling project within the GNBPA (the Proposed Action) is the subject of the analysis 

contained in this EIS. KMG and other operators would explore and develop potentially productive subsurface 

formations underlying the GNBPA by drilling up to 3,675 additional wellbores from up to 3,041 new well pads 

over a period of 10 years. The productive life of each well is estimated to be approximately 30 to 50 years. In 

support of the new wells, KMG would construct access roads, pipelines, electric power lines, compression 

facilities, and water disposal facilities. The total estimated new surface disturbance for the Proposed Action 

would be approximately 12,658 acres or about 7.8 percent of the GNBPA. 

Infill drilling would be performed on 40-acre and 20-acre surface spacing throughout the GNBPA, which is 

equivalent to a density of 16 to 32 surface well pads per section (or square mile). KMG defines a 40-acre well 

pad as the first well pad located in a governmental 40-acre quarter-quarter section. A 20-acre well pad is 

defined as the second well pad located in a 40-acre quarter-quarter section. Downhole or subsurface spacing 

would be based on the ongoing reservoir engineering evaluation and would be site-dependent, potentially 

ranging from 16 wells per section (40-acre spacing) to 64 wells per section (10-acre spacing) or more. 

DEIS 1-1 July 
 2010 
 

 

 

 Green River 

Green vi er 

White River 

Green River 

Green River 

Sweetwater

County 

Burntfork 530 

191 

Wyoming McKinnon 

Manila 43 Utah Col

City or Town

Major River

Highway

Major Road

State Boundary

County Boundary

Project Boundary 

44 Daggett 318

County 

Moffat

County

Uint

Coun

ah

ty 191 

Maeser Whiterocks Vernal

Neola Naples 149 

121 Lapoint 

Jensen 

40 Roosevelt 40

Fort

Duchesne Ballard 

262 

Myton 

Randlett 

88 

Di

45 64 

Ouray 

Duchesne

County 

Bonanza 

Rio Bl

Coun

Carbon

County 

orado 

anco

ty

R

nosaur 

Hiawatha 

Greystone 

Blue

Moun

Massadona 

tain 

Rangely 

0 2.5 5 10 15 

Scale in Miles 

Greater Natural

Area Gas Devel

Buttes 

opment

Project EIS 

Figure 1.1-1 

Regional Location Map 

Tuesday, May 6, 2008 2:15:52 PM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\APDEIS_Figures\Fig1_1-1_ProjectLocation.mxd 

1-2
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Green River 

Willow Creek 

Bitter Creek 

Hill Creek 

Evacuation Creek 

Duchesne River 

Green River 

T3S R1E T3S R2E T7S R20E T7S R24E T7S R25E T7S R21E T7S R22E T7S R23E 

T4S R1E T4S R2E 

T4S R3E 

T8S R20E T8S R25E

T8S R23E T8S R24E T8S R22E T8S R21E 

Uint

Area Coun

ah

ty 

Detail Utah 

of

STAGECOACH FIELD 

T5S R1E

T8S R18E White River

T8S R19E T5S R3E T5S R2E 

RIVER JUNCTION FIELD DEVIL'S PLAYGROUND FIELD CHAPITA WELLS FIELD 

T9S R18E T9S R19E 

T9S R20E 

T9S R21E T9S R22E T9S R23E T9S R24E T9S R25E 

OURAY FIELD 

BONANZA FIELD 

NATURAL BUTTES FIELD 

BITTER CREEK FIELD 

Township/Range 

EIS Project Area 

Named Streams and Rivers

Oil and Gas Fields near GNBPA 

Field Name 

BONANZA FIELD 

BUCK CANYON FIELD 

DEVIL'S PLAYGROUND FIELD 

LOVE FIELD 

NATURAL BUTTES FIELD 

CHAPITA WELLS FIELD 

BITTER CREEK FIELD 

ISLAND FIELD 

OURAY FIELD 

RIVER JUNCTION FIELD 

SOUTHMAN CANYON FIELD 

STAGECOACH FIELD 

UINTAH FIELD 

1 0.5 0 1 2 3 

Scale in Miles 

2 1.5 1 0.5 0 2 4 

T10S R18E ISLAND FIELD T10S R24E T10S R23E T10S R22E

T10S R19E T10S R20E T10S R21E SOUTHMAN CANYON FIELD 

UINTAH FIELD 

T10S R25E 

BITTER CREEK FI

LOVE FIELD 

ELD 

T11S R22E

T11S R19E T11S R20E T11S R21E 

T11S R18E 

T11S R24E T11S R25E

T11S R23E 

Scale in Kilometers

Greater Natural

Area Gas Developmen

Buttes

t

Project EIS 

T12S R19E T12S R20E T12S R18E 

BUCK CANYON FIELD 

T12S R21E T12S R22E T12S R23E T12S R24E T12S R25E Figure 1.1-2
 

Oil and Gas Fields
 

1-3

Thursday, January 15, 2009 10:21:38 AM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\Figures_Folder\PDEIS\Fig1_1-2_OilAndGasFields.mxd 
 

 

KMG is a private corporation intending to make a profit through development of their leases in the GNBPA. 

Specific purposes for KMG’s proposed project are to: 

•	 Conduct infill drilling on 40-, 20-, and 10-acre downhole spacing to determine the efficiency of
 

reservoir drainage of the various spacings; 

•	 Determine whether directional drilling would be technically and economically feasible for achieving 

desired downhole spacing and for producing from tight gas reservoirs in environmentally constrained 

areas; 

•	 Increase the available supply of domestically produced natural gas by a daily delivery of 500 million 

cubic feet or greater; 

•	 Increase the available supply of domestically produced liquid hydrocarbons; 

•	 Support local economies by providing and maintaining employment opportunities, sustaining local 

businesses, and expanding the tax base; 

•	 Reduce dependence on potentially unstable foreign sources of energy and contribute to our nation’s 

energy security; and 

•	 Contribute to the available supply of a clean-burning fuel for domestic and industrial use. 

In addition, KMG’s proposed natural gas and oil development project is consistent with the National Energy Act 

of 2005 and the National Energy Policy (President’s Plan) because it would provide a domestic source of 

natural gas and oil to meet the rising national energy demand. 

1.3 Purpose and Need 

The need for a BLM action is to respond to this proposal and to evaluate potential impacts resulting from 

implementing future plans and applications related to this proposal. The Federal Land Policy and Management 

Act of 1976 (FLPMA) (Public Law [PL] 94-579, 43 United States Code [USC] 1701 et seq.) recognizes oil and 

gas development as one of the "principal" uses of the public lands. Federal mineral leasing policies (Mineral 

Leasing Act of 1920 [MLA], 30 USC 188 et seq.) and the regulations by which they are enforced recognize the 

statutory right of lease holders to develop federal mineral resources to meet continuing national needs and 

economic demands. The purpose of this EIS is to facilitate the BLM decision-making process whether to 

approve, approve with modifications, or disapprove the proposed project or project components based on an 

evaluation of the expected impacts. Through this process, the BLM's purpose is to minimize or avoid 

environmental impacts to the extent possible, while allowing KMG to exercise its valid lease rights. 

1.4 Environmental Analysis Process 

This EIS was prepared in accordance with the National Environmental Policy Act (NEPA) and in compliance 

with the FLPMA, Council of Environmental Quality (CEQ) regulations (40 Code of Federal Regulations [CFR] 

Parts 1500-1508), United States (U.S.) Department of the Interior (USDOI) requirements (Department Manual 

516, Environmental Quality, including amendments under 40 CFR Part 46), and guidelines listed in the BLM 

NEPA Handbook, H-1790-1 (BLM 2008a) and in the BLM Utah NEPA Guidebook (BLM 2006a). 

According to the terms of the MLA as amended by the Federal Onshore Oil and Gas Leasing Reform Act of 

1987 (FOOGLRA), the BLM is the agency authorized to manage federal mineral interests underlying federal or 

split estate lands. Approximately 54 percent of the surface of the GNBPA and 79 percent of the mineral 

interests underlying the GNBPA are owned by the United States and administered by the BLM. Therefore, the 

BLM is the lead agency in this process, and federal jurisdiction of the GNBPA natural gas development project 

is assumed by the BLM, which would issue a Record of Decision (ROD) for this EIS. 

DEIS	 1-4 July 
 2010 
 

 

Within the ROD, the BLM Authorized Officer (AO) would determine: 

•	 Whether the analysis contained within this document is adequate for the purpose of reaching informed 

decisions regarding GNBPA project development; 

•	 Whether to approve the Proposed Action, select a different alternative, or a combination of 

alternatives; 

•	 Whether the Proposed Action or other alternatives are in conformance with applicable land and 

resource management plans and programmatic plans developed under NEPA, FLPMA, CEQ 

regulations, USDOI Department Manual 516, and the BLM NEPA Handbook H-1790-1 (BLM 2008a); 

and 

•	 The Conditions of Approval (COAs), if any, that may be attached to the ROD. 

The BLM decision would only apply to federal lands; however, the analyses in this EIS consider the impacts for 

all proposed activities regardless of surface ownership. 

Uintah County and the Bureau of Indian Affairs (BIA) are cooperating agencies. Copies of the Preliminary Draft 

EIS were submitted to Uintah County and the BIA for their review and comment prior to distribution to the 

public, and their comments were taken into account. 

1.4.1 Decisions to be Made After the EIS Process 

Although the ROD may approve the proposed oil and gas wellfield development on a conceptual basis, a 

site-specific environmental review of areas proposed for surface disturbance and sub-surface mineral 

extraction would be completed to determine the final location of facilities based on environmental 

considerations. Prior to drilling on BLM-administered land, the project proponent must submit an Application 

for a Permit to Drill (APD) to the BLM, which includes a Surface Use Plan of Operation and a Drilling Plan. At 

that time, the BLM would conduct a site-specific NEPA review and attach appropriate measures to the permit 

to protect natural and human resources. The BLM is responsible for approval of the drilling program, protection 

of groundwater and other sub-surface resources, and final approval of the APD on BLM-administered lands 

and/or minerals. Access roads and utilities such as pipelines and electrical powerlines on federal lands may 

require a right-of-way (ROW) grant from the BLM, based on the APD applications or other independent 

applications. The regulations and guidelines that are used to administer the construction and operation of oil 

and gas facilities are further discussed in Section 2.3, Management Common to All Alternatives. 

Tribal surface and mineral estate is administered in trust by the BIA. While the BLM would approve drilling 

permits on Tribal Lands, approval of surface disturbance and granting of ROWs would be approved by the 

BIA. All lands belonging to the State of Utah within the GNBPA are administered by the Utah School and 

Institutional Trust Lands Administration (USITLA). USITLA issues oil and gas leases and would approve 

surface disturbance activities on state lands. Approval of APDs on state and privately owned lands would be 

subject to requirements of the Utah Division of Oil, Gas, and Mining (UDOGM). 

1.5 Legal and Policy Considerations 

1.5.1 Leases and Leasing History 

KMG operates the oil and gas leases underlying approximately 85 percent of all lands in the GNBPA. For 

those leases where KMG is the designated operator, KMG is responsible for ensuring that lease stipulations 

are followed during oil and gas development. 

Many of the leases covering BLM-administered minerals within the GNBPA were issued before the current 

Resource Management Plan (RMP) for the project area was approved and, therefore, may not contain 

DEIS	 1-5 July 
 2010 
 

 

stipulations other than the standard lease terms. Typical stipulations that may apply to federal oil and gas 

leases in the vicinity of the GNBPA include: 

•	 Stipulations to protect lands in oil shale withdrawal, Executive Order (EO) 5327 of April 15, 1930; 

•	 Surface disturbance restrictions to protect erosive soils and sensitive plants; 

•	 Seasonal restrictions to protect raptor species and other wildlife; 

•	 Threatened and Endangered Species Act of 1973 (ESA) stipulations; and 

•	 Protection of cultural resources. 

Surface stipulations and timing restrictions, threatened and endangered species lease notices for oil and gas 

development, and BLM-committed conservation measures that may apply to federal leases within the GNBPA 

are provided in the Vernal Field Office ROD and Approved RMP (BLM 2008b). 

1.5.2 Conformance with BLM Management Plans and Policies 

Policies for development and land use decisions for federal lands and minerals within the GNBPA are 

contained in the following federal documents. 

•	 The Vernal Field Office ROD and Approved RMP (BLM 2008b) 

•	 Environmental Analysis Record Oil and Gas Leasing Program for the Vernal District (BLM 1975) 

Additional guidance for the GNBPA is contained in the following NEPA documents. 

•	 The Vernal Field Office Proposed RMP and Final EIS (BLM 2008c) 

•	 EA No. 1997-13, Coastal Oil & Gas Corporation Natural Buttes Unit Environmental Assessment (EA), 

Uintah County, Utah (BLM 1997a) 

•	 Final EA of Coastal’s Proposed Development of the Ouray Field, Uintah County, Utah (Buys & 

Associates 2000) 

•	 EA No. UT-080-2006-240, Kerr-McGee’s Bonanza Area EA (BLM 2006b) 

•	 EA No. UT-080-2006-253, Kerr-McGee’s Love Unit EA and Biological Assessment (BA) (BLM 2006c) 

•	 EIS No. UT-080-2005-0010, EOG Resources’ Chapita Wells-Stagecoach Area EIS and BA 

(BLM 2008d)
 

•	 EIS No. UT-080-2003-0369V, Questar Exploration and Production Company’s Greater Deadman 

Bench EIS (BLM 2008e) 

Management objectives within the Vernal RMP ROD include leasing oil and gas resources while protecting or 

mitigating impacts to other resource values. As such, the proposed GNBPA natural gas development project is 

consistent with the management decisions contained in the RMP. It is noted that surface occupancy or some 

existing oil and gas leases may not be in conformance with the Vernal RMP because existing lease terms are 

not affected by the recently approved RMP. To the extent feasible, the proposed project would be expected to 

comply with the BLM's Utah Public Lands Health Standards (BLM 1997b). The proposed project also would be 

required to comply with federal policies related to riparian habitats, floodplains, and drainages. 

1.5.3 Consistency with Other Federal and Local Land Management Plans and Policies 

The BIA is a cooperating agency on this EIS. A formal management plan does not exist for the Uintah and 

Ouray Reservation; however, the elected Ute Tribe Business Committee and the BIA determine approval of 

land use activities on Tribal Lands. Production from tribal leases provides royalties, tax revenues, and surface 

DEIS	 1-6 July 
 2010 
 

access and use fees to the Tribe, which contributes to the Tribe’s economic well being. The Proposed Action is 

consistent with the regulatory responsibilities of the BIA, which include promoting the economic development 

objectives of the Ute Tribe under its government-to-government relationship with, and trust responsibility to, 

the Tribe. Therefore, the range of the BIA’s reasonable alternatives is limited to those that would serve the 

Tribe’s economic development objectives consistent with the trust responsibility. 

There are no comprehensive State of Utah plans for the GNBPA. USITLA has leased all of the state lands 

within the GNBPA for oil and gas production. Because the main objective of USITLA is to produce funding for 

the state school system, and because production on federal leases could lead to further interest in drilling state 

leases in the area, the Proposed Action is assumed to be consistent with the objectives of USITLA. 

Uintah County has developed a Uintah County General Plan (Uintah County 2005) regarding development on 

public lands within the County. The Uintah County General Plan emphasizes multiple-use public land 

management practices, responsible use, and optimum utilization of public land resources. Multiple-use is 

defined in the plan as including, but not limited to, the following historically and traditionally practiced resource 

uses: grazing, recreation, timber, mining, oil and gas development, agriculture, wildlife habitat, and water 

resources. The proposed project is consistent with the Uintah County General Plan. 

1.5.4 Authorizing Actions and Project Relationships to Statutes and Regulations 

Private exploration and production from federal oil and gas leases is an integral part of the BLM oil and gas 

leasing program under authority of the MLA and FLPMA. The BLM oil and gas leasing program encourages 

development of domestic oil and gas reserves in accordance with the Mining and Minerals Policy Act and the 

reduction of U.S. dependence on foreign energy sources. Natural gas is an integral part of the energy future 

for the U.S. due to its availability and the presence of an existing market delivery infrastructure. The 

environmental advantages of burning natural gas, rather than coal, were emphasized by the U.S. Congress 

and by the President when the Clean Air Act (CAA) Amendments of 1990 were signed into law. Furthermore, 

the Energy Policy acts of 2001 and 2005 emphasize the development of domestic natural gas reserves for 

supply and economic stability. 

Various aspects of oil and gas development are regulated under the BLM Onshore Oil and Gas Orders, as 

authorized in 43 CFR 3160 including: 

• Onshore Order No.1 – Approval of Operations; 

• Onshore Order No. 2 – Drilling Operations; 

• Onshore Order No. 3 – Site Security; 

• Onshore Order No. 4 – Measurement of Oil; 

• Onshore Order No. 5 – Measurement of Gas; 

• Onshore Order No. 6 – Hydrogen Sulfide Operations; 

• Onshore Order No. 7 – Disposal of Produced Water; 

• Onshore Order No. 8 – Well Completions/Workovers/Abandonment (Proposed Rule); 

• Onshore Order No. 9 – Waste Prevention and Beneficial Use of Oil and Gas (Not Published); and 

• Notices to Lessees. 

In addition to the BLM, numerous other federal, state, and local governmental agencies may be involved in 

regulation of oil and gas development. A summary of the key permits, approvals, and authorizing actions that 

may apply to the action alternatives is provided in Table 1.5-1. 

DEIS 1-7 July 2010 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 1.5-1 Key Federal, State, and Local Permits, Approvals, and Authorizing Actions for 

Construction, Operation, Maintenance, and Abandonment of the Proposed Action 

Issuing Agency Name and Nature of Permit/Approval Regulatory Authority (if appropriate) 

FEDERAL AGENCIES 

USDOI 

BLM 

Permit to Drill, Deepen, or Plug Back (APD/Sundry 

Process); Controls drilling for oil and gas on federal 

onshore lands. Also see Chapter 2.0, Table 2.3-1. 

MLA (30 USC 181 et seq.); 43 CFR 3162; 

National Mining and Minerals Policy Act of 1970, 

the FOOGLRA of 1987, (Onshore and Gas Orders 

#1 and #2 [43 CFR 3164]) 

ROW Grants and Temporary Use Permits; grants 

ROW use on BLM-managed lands. 

MLA as amended (30 USC 185); 43 CFR 2880; 

FLPMA (43 USC 17611771); 43 CFR 2800 

Antiquities, Cultural, and Historic Resource Permits; 

issue antiquities and cultural resources use permits to 

inventory, excavate, or remove cultural or historic 

resources from federal lands. 

Antiquities Act of 1906 (16 USC Section 431-433); 

Archaeological Resources Protection Act of 1979 

(ARPA) (16 USC Sections 470aa47011); 43 CFR 

Part 3; Section 106 of the National Historic 

Preservation Act (NHPA) 

Approval to dispose of produced water; controls 

disposal of produced water from federal leases. Also 

see Chapter 2.0, Table 2.3-1. 

MLA (30 USC 181 et seq.); 43 CFR 3164; 

Onshore Oil and Gas Order No. 7 

Pesticide Use Permit and Daily Pesticide Application 

Record. 

BLM Authorization for Herbicide Applications on 

Federal Lands 

Federal Noxious Weed Act compliance. Plant Protection Act of 2000 (PL 106-224, 7 USC 

7701); Federal Noxious Weed Act of 1974, as 

amended (USC 2801-2814); EO 13112 of 

February 3, 1999 

Initiation of Section 7 consultation. Section 7 of the ESA, as amended (16 USC et 

seq.) 

Mineral Material Sales Permit; for use of BLMmanaged borrow pits in road construction. Materials Act of 1947 as amended (30 USC, 601 

et seq.) 

Paleontological Resource Use Permit; approval for 

surveys and potential data collection at well pads and 

road sites. 

FLPMA (302[b]) 

BIA ROW Grants and Temporary Use Permits; grants 

ROW use on Tribal Lands. 

25 CFR 169 

Tribal/allotted Land Activities. In coordination with the 

Northern Ute Tribe, the BIA has authority to approve 

any and all activities on Tribal/allotted lands. 

25 CFR 225 

U.S. Fish and Wildlife Service 

(USFWS) 

ESA Section 7 consultation. Section 7 of the ESA, as amended (16 USC et 

seq.) 

Migratory Bird Treaty Act (MBTA) consultation. MBTA of 1918, as amended (15 USC 703-712); 

EO 13186 

Bald and Golden Eagle Protection Act consultation. Bald Eagle Protection Act of 1940, as amended 

(16 USC 668-668d) 

Section 404 Permit Consultation; review of permit for 

compliance with ESA. 

Consultation as established under the Fish and 

Wildlife Coordination Act 

Advisory Council on Historic 

Preservation 

Cultural resources compliance (Section 106); 

coordinated with the Utah State Historic Preservation 

Officer (SHPO). 

NHPA, Section 106 

U.S. Department of Defense 

Army Corps of Engineers 

(USACE) – Sacramento District 

Section 404 permit (Nationwide and Individual); 

controls discharge of dredged or fill materials into 

waters of the U.S. 

Section 404 of the Clean Water Act of 1972 

(CWA) (33 USC 1344) 

U.S. Environmental Protection 

Agency (USEPA) 

Region 8 

USEPA is required to review and comment on major 

federal actions that have a significant impact on the 

human environment. In addition, the northwestern 

portion of the GNBPA lies within the tribal boundary 

established by the 10th Circuit Court. USEPA has 

responsibility for implementing environmental programs 

for Indian Country (as defined at 18 USC § 1151) until 

Tribal governments are formally authorized to implement 

these programs. USEPA’s role is to provide scoping 

comments, review EISs, and provide CAA and CWA 

permitting, information, and appropriate technical 

assistance during and following the environmental 

analysis process. 

CAA, as amended, 42 USC Annotated (USCA) 

Section 7410-762 (PL 95-604, PL 95-95) Federal 

Water Pollution Control Act, as amended by the 

CWA, 33 USCA Section 1251-1376 (PL 92-500, 

PL 95-217) Safe Drinking Water Act, 452 USCA 

Section 300F-300J-10 (PL 93-523) 

Underground Injection Control (UIC) – also see 

Chapter 2.0, Table 2.3-1. 

UIC (40 CFR 146.21 through 146.24) 

DEIS 1-8 July 
 2010 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 1.5-1 Key Federal, State, and Local Permits, Approvals, and Authorizing Actions for 

Construction, Operation, Maintenance, and Abandonment of the Proposed Action 

Issuing Agency Name and Nature of Permit/Approval Regulatory Authority (if appropriate) 

U.S. Department of 

Transportation (USDOT) 

Utah 

Approval of construction and operation of natural gas 

pipelines. Prescribes minimum safety requirements for 

pipeline facilities and the transportation of natural gas. 

Pipeline safety regulations (49 CFR 190-199) 

STATE AGENCIES 

Utah Division of State History 

Utah SHPO 

Consult on Section 106 compliance process; approve 

cultural resource clearances; provide for protection of 

cultural resources. 

NHPA, Section 106 

Antiquities Annual Permit; to conduct archeological 

surveys on state and private lands. 

Archaeological Permit Rules Utah R694-1 

Antiquities Projects Permit; regulates all archeological 

excavations on state and private lands. 

Archaeological Permit Rules Utah R694-1 

Utah Department of Natural 

Resources (UDNR) 

UDOGM 

Regulates activities associated with drilling of oil and 

gas wells in state, including pressure monitoring and 

permitting of injection wells and well spacing – also 

see Chapter 2.0, Table 2.3-1. 

Permitting of Wells, Utah R649-3-4 et seq., R649-

3-18; UIC Rules Utah R649-5 and R649-3-2 

Division of Water Rights Review and issuance of stream alteration permit. Utah Code 73-3-29 

Approval to Appropriate Water; grants permit to 

appropriate water. 

Utah Code 73-3-2 

Division of Water Resources Determination of adequate water supply and 

cumulative impacts on water supply. Section 401, 

CWA Water Quality Certification Stream and Wetland 

Crossings Section 401, CWA Water Quality 

Certification Stream and Wetland Crossings. 

CWA as it pertains to state government 

(Section 401) 

Utah Division of Wildlife 

Resources (UDWR) 

Protection and management of state wildlife and fish 

resources. Participation in the Section 404 Permit 

process and review of the Draft EIS. 

Utah Code 23-22 

Consultation and input on fish and wildlife habitat for 

state listed species. 

Utah Code 23-13 through 23-21 

Forestry, Fire, and State Lands ROW grant for construction activities on State lands. Easement Rules Utah R652-40 

Utah Department of 

Environmental Quality (UDEQ) 

Division of Water Quality 

Protection of water quality. Responsible for the Utah 

Pollutant Discharge Elimination System (UPDES) 

storm water discharge permit. Prior to construction the 

preparation of a Storm Water Pollution Prevention Plan 

(SWPPP) is required. 

Utah Code 19-5; UPDES Rules Utah R317-8 

UPDES Construction Dewatering Permit; discharge of 

dewatering and hydrostatic test waters from property to 

U.S. waters. 

Utah Code 19-5; UPDES Rules Utah R317-8 

Division of Air Quality Approval order; permit for operation of certain 

stationary emissions sources; Air Quality Permit to 

Construct. 

Utah Code Stationary Source Rules Utah R307-

210; Operating Permit Rules Utah R307-415 

New Source Review Permit; controls emissions from 

new or modified sources. 

New and Modified Source Permit Rules Utah 

R307-401 

Fugitive Dust Control. Fugitive Dust Rules Utah R307-205 

Utah Department of 

Transportation (UDOT) 

Transport Permit; authorizes oversize, over length, and 

overweight load transportation on state highways. 

Motor Carrier Rules Utah R909-1 

Encroachment Permit; authorizes pipeline crossings of 

access roads that tie into state or federal highways. 

Access Openings Rules Utah R933-3 

USITLA Issue a ROW grant/permit for construction and use 

activities on State Trust Lands. 

USITLA Rights-of-Entry Rules Utah R850-41 

LOCAL AGENCIES 

Uintah County Commissioners County zoning/land use plan consultation. Uintah County Code, Uintah County General Plan 

(Uintah County 2005) 

Road Use and Opening permits. Uintah County Code 

Construction permits, licenses. Uintah County Code 

Noxious Weed Act enforcement. Uintah County Code 

Solid Waste Disposal permits. Uintah County Code 

Special Use and Conditional Use permits. Uintah County Code 

DEIS 1-9 July 
 2010 
 

 

1.6 Scoping 

1.6.1 Public Scoping 

The BLM conducted public and internal scoping to solicit input and identify environmental issues and concerns 

associated with the proposed project. The public scoping process was initiated on October 5, 2007, with the 

publication of a Notice of Intent (NOI) in the Federal Register. The BLM prepared a scoping information notice 

and provided copies to the public, other government agencies, and Tribes. These announcements included 

information on a public scoping and open house, which was held at the Western Park Conference Center in 

Vernal, Utah, on October 23, 2007. The official scoping period ended November 5, 2007. 

Written comments were received during the public scoping period. Public response to the NOI and meetings 

included a total of nine letters: two from federal agencies, one from the state agencies, one from a county 

agency, one from a non-government organization, and four from industry or private individuals. 

During the scoping period, the following key concerns were identified for consideration in preparing the Greater 

Natural Buttes EIS. 

•	 Analysis of proposed development throughout the GNBPA in a manner compatible with previous or 

ongoing NEPA projects covering portions of the proposed GNBPA. 

• Off-site mitigation opportunities or other management options. 

•	 Laws, regulations, or BLM policies that may have changed since the Book Cliffs RMP. 

•	 Impacts associated with tribal trust resources. 

•	 Detailed transportation analysis that identifies methods to reduce traffic during drilling and production, 

defines maintenance standards, and determines the ultimate disposition of roads at project 

termination. 

•	 Generation of solid wastes including garbage and human waste. 

•	 Disposal of produced water on-site, use of produced water in drilling and fracing operations, and use 

of gathering water with pipelines versus trucking water to disposal sites. 

•	 Comprehensive reclamation plan that includes post-reclamation monitoring and annual reporting. 

•	 Additional surface disturbance associated with pipelines and analysis of surface versus sub-surface 

pipelines. 

•	 Feasibility of locating production facilities outside the 100-year floodplain. 

•	 Comprehensive air-quality analyses and region-wide air-quality modeling. 

•	 Direct and cumulative impacts to pronghorn population, forage availability, and ability of numbers to 

meet herd unit objectives. 

•	 Direct and cumulative impacts to sage grouse leks and surrounding nesting and brood-rearing 

habitats with consideration of mitigative habitat restoration and other mitigation measures. 

•	 Cumulative impacts on current grazing permits, including direct impacts to livestock, forage, water 

developments, and economic returns. 

•	 Identification of hunting value of lands in the GNBPA and impacts to hunting activities. 

•	 Impacts to visual resources and recreational use along the White River. 

•	 Economic effects of the proposed project to the local economy, the state, and the school trust lands. 

•	 Balance between environmental protection and economic growth. 

DEIS	 1-10 July 2010 
 

1.6.2 Internal Scoping and Issue Identification 

The BLM has compiled a list of resources potentially present in the Vernal Field Office area. These resources 

represent issues considered in all Vernal Field Office EAs and EISs and are discussed and analyzed in 

Chapters 3.0, 4.0, and 5.0 of this document. A listing of these resources and their status within the GNBPA is 

presented in Appendix B. The resources and issues identified in this appendix that are not within the vicinity 

of the GNBPA, and therefore would not be affected by the proposed project, are not carried forward for 

detailed analysis in Chapters 3.0, 4.0, and 5.0 of this EIS. 

DEIS 1-11 July 2010 
2.0 Proposed Action and Alternatives 

This chapter defines the GNBPA boundaries, describes the existing and approved oil and gas facilities 

present within the GNBPA (Section 2.2), discusses standard development and production activities 

(Section 2.5), and describes the alternatives analyzed in this document. In developing the alternatives, the 

BLM followed guidance set forth in the BLM Instruction Memorandum No. 2005-247, Attachment 1, which 

provides recommendations on developing a range of reasonable alternatives for oil, gas, and geothermal 

development activities. Based on this guidance, the BLM developed the following alternatives for analysis in 

this EIS. 

•	 No Action Alternative: This alternative assumes that approval of KMG’s proposed project is 

denied and no new drilling would occur on Federal mineral estate except that currently permitted 

and approved under previous NEPA documents (Section 2.4). 

•	 Proposed Action Alternative: This alternative consists of KMG’s proposal to develop an
 

additional 3,675 wells drilled from a maximum of 3,041 new well pads placed at up to 20-acre 

surface spacing within the GNBPA (Section 2.6). 

•	 Resource Protection Alternative: This alternative consists of the same number of subsurface 

wells as the Proposed Action Alternative drilled from a reduced number of well pads (approximately 

1,484) at 40-acre surface spacing to reduce the surface disturbance of the project (Section 2.7). 

Directional drilling would need to be used under this alternative to achieve the same number of 

subsurface wells (3,675) as the Proposed Action Alternative from a reduced number of surface well 

pads. The Resource Protection Alternative is the BLM preferred alternative. 

•	 Optimal Recovery Alternative: This alternative maximizes the recovery of natural gas resources 

by increasing well surface spacing to 10 acres for an estimated 13,446 wells within the GNBPA 

(Section 2.8). 

The No Action Alternative and each of the various action alternatives are discussed in terms of alternativespecific activities and schedule, alternative-specific design features, and surface disturbance summaries. 

Alternatives considered but eliminated from detailed analysis are discussed in Section 2.9. The analysis of 

each alternative in Chapter 4.0 focuses on the new disturbance that would occur under each alternative. 

2.1 Greater Natural Buttes Project Area 

KMG and other operators active in the GNBPA continue to implement approved oil and gas development 

including drilling new wells and constructing new infrastructure. Additionally, KMG proposes to drill new wells 

as infill to all productive formations, including but not limited to, the Green River Formation, Wasatch 

Formation, Mesaverde Group (including the Blackhawk Formation), Mancos Shale, and Dakota Sandstone. 

Target depths for the wells throughout this area would range from approximately 2,000 to 16,000 feet, with the 

primary focus on 2 formations: the Wasatch Formation where the wells would range from 2,400 to 6,500 feet 

deep and the Mesaverde Group where they would range from 3,900 to 11,000 feet deep. The total number of 

wells drilled and yearly drilling activity would depend largely on factors outside of KMG’s control such as 

production success, engineering technology, reservoir characteristics, economic factors, commodity prices, rig 

availability, and lease stipulations. 

The GNBPA consists of approximately 162,911 acres in an existing gas producing area located in T8S, 

R20-23E; T9S, R20-24E; T10S, R20-23E; and T11S, R21-22E in Uintah County, Utah. The lands included 

in the GNBPA are located in all or a portion of the townships illustrated in Figure 1.1-2. 

DEIS	 2-1 July 2010 
 

 

 

 

The number of wellbores on any particular surface location or pad would vary according to KMG’s success 

in deepening existing wellbores to the Mesaverde Formation as well as the ability to drill viable directional 

wellbores in environmentally constrained areas. 

The project wells and facilities would be constructed and operated within the GNBPA on lands owned by the 

federal government, the State of Utah, private landowners, and lands held in trust for the benefit of the Ute 

Tribe. Tribal allottees are individual Native Americans who received land and sometimes mineral interests 

directly from the federal government. Lands with separate surface and mineral ownership, so called “split 

estate lands,” comprise approximately 18 percent of land within the GNBPA. Surface ownership and 

ownership of oil and gas mineral rights are summarized in Table 2.1-1. 

Table 2.1-1 Surface and Oil and Gas Minerals Ownership within the GNBPA 

Surface Owner Surface Acres Percentage Minerals Acres1 Percentage 

BLM 88,565 54.4 117,116 71.9 

Ute Indian Tribe 39,399 24.2 10,855 6.7 

State of Utah 32,755 20.1 32,685 20.1 

Private2 2,192 1.3 2,255 1.4 

Totals 162,911 100 162,911 100 

1 Mineral ownerships reflect relative accuracy only. 

2 Includes allottees. 

2.2 Existing Oil and Gas Infrastructure in the GNBPA 

Based on UDOGM information (October 2007) for existing oil and gas infrastructure in the GNBPA, 

1,562 vertical productive wells have been drilled on single well pads and are in operation. Table 2.2-1 

identifies those existing or approved oil and gas facilities that are present within the GNBPA. 

Table 2.2-1 Existing Facilities 

Facility 

Multiplier 

(number 

or miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Estimated Existing 

Surface Disturbance 

(acres) 

Roads 

Access Roads1 391 mile 45 feet 2,130 

Well Pads 

Single Existing Well Pads 1,562 each 2.5 acre 3,905 

Construction/Production Facilities 

Mancamps 2 each 5 acre 10 

Compressor Stations 23 each 16 acre 368 

Chapita Process/Compression Plant 1 each 70 acre 70 

Evaporation/Recycle Facilities 3 each 20 acre 60 

Water Injection Facilities 5 each 3 acre 15 

Facilities Subtotal 523 

DEIS 2-2 July 2010 
 

 

 

 

 

 

 

 

 

Table 2.2-1 Existing Facilities 

Facility 

Multiplier 

(number 

or miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Estimated Existing 

Surface Disturbance 

(acres) 

Linear Facilities 

Gas Gathering Pipelines (cross-country) 20 mile 20 feet 47 

Gas Transport Pipelines (buried) 65 mile 75 feet 591 

Water Pipelines (buried) 20 mile 75 feet 182 

Electric Power Lines 32 mile 100 feet 388 

Linear Facilities Subtotal 1,208 

Total Existing Disturbance 7,766 

Total Existing Disturbance as Percent of GNBPA 4.8% 

Existing Surface Disturbance Interim Reclamation Estimates2 

Reclaimable Existing Surface Disturbance (acre) 3,267 

Reclaimable Percent of Existing Surface Disturbance 42% 

Reclaimable Existing Surface Disturbance as % of GNBPA 2.0% 

1

 Assume access road length of 0.25 mile/well pad for existing wells. 

2

 Interim reclamation estimates are based on the potential to reclaim (i.e., "reclaimable") 0.5 acre per existing well pad, 27 feet ROW for roads, and all 

Linear Facilities summarized in the table above. 

2.3 Management Common to All Alternatives 

Key documents and associated procedures that control oil and gas development and production on public, 

Tribal, state, and private lands are presented in Table 2.3-1. Following the completion of the NEPA 

compliance process, but prior to activities occurring on public or Tribal Lands, approvals for wells and 

ancillary facilities must be granted by the BLM and BIA as part of the requirements set forth by the Onshore 

Oil and Gas Order No. 1, “Approval of Operations on Onshore Federal and Indian Oil and Gas Leases,” 

issued under 43 CFR 3160. This process includes two procedural options for obtaining approval to drill a 

well. When operators decide to drill a well on BLM-administered lands, either a Notice of Staking (NOS) or 

an APD must be submitted to the BLM. A separate APD is submitted to UDOGM. No surface activity can be 

initiated on BLM-administered land until the well drilling application is approved by the BLM. Roads, 

pipelines, and other surface facilities constructed on BLM-administered lands, but outside of the lease or 

unit would require grant of a federal ROW from the BLM. Well facilities would require a federal bond. Tribal 

surface and mineral estate is administered in trust by the BIA. While the BLM would approve drilling permits 

on Tribal Lands, surface disturbance and ROWs would be approved by the BIA. All lands belonging to the 

State of Utah within the GNBPA are administered by the USITLA. Approval of APDs on state and privately 

owned lands would be subject to requirements of the UDOGM. 

Table 2.3-1 Key Oil and Gas Development and Production Guidelines Applicable to all Alternatives 

Activity Governed by Guidance Documents Requirements 

Approvals for Well 

Drilling, Completion, 

and Production 

Federal 

State 

BLM Onshore Order #1 (43 CFR 3164.1; 48 Federal 

Register 48916 and 48 Federal Register 56226); 

43 CFR 3162.5-1 Environmental Obligations. 

BIA Approval of Operations (25 CFR 225.32). 

UDOGM: Rule R649-3-4. Permitting of Wells to be 

Drilled, Deepened, or Plugged-Back; R649-3-18. 

On-site Predrill Evaluation. 

• Preparation of an APD, including a 

surface use plan of operations and a 

drilling and completion plan. 

• Inspections prior to construction and 

drilling approval. 

DEIS 2-3 July 2010 
 

 

 

 

 

 

Table 2.3-1 Key Oil and Gas Development and Production Guidelines Applicable to all Alternatives 

Activity Governed by Guidance Documents Requirements 

Access Road, Well 

Pad, and Utility 

Design and 

Construction 

Federal 

State 

County 

BLM “Surface Operating Standards for Oil and Gas 

Exploration and Development” (USDOI and U.S. 

Department of Agriculture [USDA] 2007); ROW 

acquisition (43 CFR 2800 et al.). 

USEPA CAA Fugitive Dust Emission Standards (40 

CFR 50), CWA Storm Water Discharges (40 CFR 

122.26). 

USACE CWA Permitting of Dredge and Fill 

Operations (33 CFR 323). 

UDEQ Rule 307-205-7: Mining Activities Fugitive 

Dust Emissions Standards. 

UDOT Rule R933-3: Relocation or Modification of 

Existing Authorized Access Openings or Granting 

New Access Openings on Limited Access 

Highways. 

Uintah County General Plan, Chapter 7e: Roads 

and Transportation Planning (Uintah County 2005). 

• Minimum standards for roads, well pads, 

and utilities. 

• Surface management BMPs. 

• Storm water discharge. 

• Dredge and fill operations. 

• Acquisition of federal ROWs. 

• Fugitive dust control requirements. 

• Requirements for encroachment onto 

State and County ROWs. 

Drilling Operations Federal 

State 

BLM Onshore Order #2 (43 CFR 3164.1; 53 Federal 

Register 46790) 

UDOGM: Rules R649-3-6 (Drilling Operations); 

R649-3-7 Well Control; R649-3-8 Casing Program; 

R649-3-9 Protection of Upper Productive Strata; 

R649-3-15 Pollution and Surface Damage Control; 

R649-3-14 Fire Hazards on the Surface; 

R614-2-4 Drilling Industry – Fuel Protection and 

Prevention; R68-9 Utah Noxious Weed Act. 

• Well control methods. 

• Drilling reporting. 

• Well casing. 

• Groundwater protection methods. 

• Pollution control methods. 

• Fire prevention. 

• Noxious weed control. 

Site Security Federal BLM Onshore Order #3 (54 Federal Register 8056). • Facility security requirements. 

Measurement of Oil Federal BLM Onshore Order #4 (54 Federal Register 8086). • Measurement methods for produced oil. 

Measurement of Gas Federal BLM Onshore Order #5 (54 Federal Register 8100). • Measurement methods for produced gas. 

Disposal of Produced 

Water 

Federal 

State 

BLM Onshore Order #7 (58 Federal Register 

47354). 

UDOGM Rule R649-9 Waste Management and 

Disposal; UDOGM Rule R649-8 Reporting and 

Report Forms 

• Criteria for the management and disposal 

of produced water. 

• Reporting and recordkeeping 

requirements. 

Installation of 

Compression 

Facilities 

Federal 

State 

USEPA CAA (40 CFR 50 through 97) 

UDEQ Rule R210-1: Stationary Sources, R214-2: 

National Emissions Standards for Hazardous Air 

Pollutants, R401-4: Permitting New or Modified 

Stationary Sources. 

• Minimum standards for air emissions. 

• Permit requirements and public notices. 

DEIS 2-4 July 2010 
 

Table 2.3-1 Key Oil and Gas Development and Production Guidelines Applicable to all Alternatives 

Activity Governed by Guidance Documents Requirements 

UIC (Disposal of 

produced water) 

Federal 

State 

USEPA UIC (40 CFR 146.21 through 146.24). 

UDOGM Rule R649-5 UIC of Recovery Operations 

and Class II Injection Wells (R649-5-1 through 

R649-5-7, R693-2). 

• Permit information requirements and 

public notices. 

• Well construction methods. 

• Testing and monitoring procedures. 

• Operational monitoring and reporting. 

Well Abandonment 

and Reclamation 

Federal 

State 

BLM 43 CFR 3162.3-4 Well Abandonment. 

UDOGM Rule R649-3-24; and R6493-34 Well Site 

Restoration. 

• Well plugging and abandonment. 

• Wellsite restoration process. 

The drilling application process requires an operator to schedule an on-site inspection of each proposed 

wellsite, which is attended by a representative of the appropriate Surface Management Agency (SMA) 

(BLM, BIA/Tribe, and/or UDOGM) and, for split-estate lands, may be attended by the private surface owner. 

The BLM would conduct a site-specific NEPA review and analysis prior to issuing an APD. 

The objective of the on-site inspection is to review the proposed locations for wells and well pads, access 

roads, and ancillary facilities for consideration of the following: site-specific topography; topsoil/subsoil 

stockpiles; natural drainage and erosion control; vegetation and wildlife resources; historical and cultural 

resources; paleontological resources; and any other surface issues that may become apparent during 

inspection or are addressed in the lease stipulations. 

The drilling application process also requires that an operator design individual well completions to protect 

fresh water aquifers. A BLM geologist and/or hydrologist performs an independent review of each APD 

utilizing Utah Geological Survey (UGS) and U.S. Geological Survey (USGS) geologic and hydrologic data 

and maps to generate a geologic report. The geologist and/or hydrologist identifies usable ground water and 

mineral-bearing zones that require protection, including Sole Source Aquifers (SSAs) and Drinking Water 

Source Protection Zones (DWSPZs). The petroleum engineer reviews the casing and cementing portions of 

the drilling plan to ensure adequate protection of those zones identified by the geologic report. The BLM 

further reviews the surface use plan to determine the adequacy of reserve pit design. COAs are attached to 

the APD as necessary. 

Access roads and well pads located on federal public lands are designed and constructed under the 

guidelines contained in “Surface Operating Standards and Guidelines for Oil and Gas Exploration and 

Development" (Gold Book) (USDOI and USDA 2007). Where possible, new roads, pipelines, and utility lines 

are located along existing linear ROWs in order to minimize additional surface disturbance. Construction of 

access roads, well pads, and other associated utilities is regulated under the CAA by the USEPA and 

UDEQ for fugitive dust emissions, and under the CWA by USEPA for storm water discharges and by the 

USACE for dredge and fill operations. UDOT Rule 307-205-7 and the Uintah County General Plan (Uintah 

County 2005), Chapter 7e requirements control encroachment on state and county ROWs. 

Drilling and completion operations, including aquifer protection and pollution control methods, are outlined in 

the BLM Onshore Order No. 2 and the UDOGM Rules, which also include well spacing requirements. 

Operators are subject to various federal or state bonding requirements, depending on the SMA. Oil and gas 

production operations on federal lands are managed under Onshore Order No. 3, while Orders No. 4 and 

No. 5 address documentation of hydrocarbon production for taxes and royalties. The requirements for 

disposing of water produced during drilling and operations are addressed in Onshore Order No. 7. KMG has 

incorporated elements of the Onshore Orders and the BLM standard procedures into its standard operating 

practices for drilling and surface management. 

DEIS 2-5 July 2010 
 

 

 

 

 

 

Emissions standards associated with the installation of compression facilities, including upgrades to existing 

facilities and construction of new facilities, is regulated under the CAA by the USEPA and permitted through 

UDEQ on all lands within the GNBPA except on Tribal Lands where permitting is conducted through USEPA 

Region VIII. 

The USEPA has promulgated rules for underground water injection that are applicable for wells located in 

the GNBPA. These rules address the allowable water pressures in the receiving formations, and the 

monitoring and reporting of these pressures. Monthly injection volumes and pressures are reported to the 

State of Utah or the USEPA, depending on jurisdiction. Well injection rates and pressures are measured 

daily through the use of surface monitoring devices at each injection well. In addition, well casing integrity 

tests must be completed at intervals as mandated by the State of Utah and the USEPA to ensure isolation 

of the injection interval. 

Proposals for drilling and well testing are contained in a detailed drilling program included as a required 

portion of federal APD packages. Both the BLM and UDOGM prescribe procedures for well plugging and 

abandonment at the end of the life of a well, as well as site reclamation requirements and procedures. 

2.4 No Action Alternative 

Under the No Action Alternative, drilling and completion of development wells and infrastructure would 

continue as described in approved NEPA decision documents. A summary of surface disturbance 

associated with implementation of the No Action Alternative is presented in Table 2.4-1. This includes 

facilities disclosed through other NEPA documents or approved by other agencies but not yet constructed 

as of October 2007. This date was selected as a fixed point in time to represent information that is 

continuously changing. While the BLM recognizes there is a gap between this point in time and the 

publication date of this document, the information provides a consistent basis for evaluation of the project 

and alternatives. 

The BLM recognizes that reclamation is difficult and is likely to require a long time to achieve in the Uinta 

Basin. Therefore, for purposes of analysis in this EIS, the total surface disturbance for the proposed project 

and alternatives without consideration of reclamation was used. The surface disturbance that would be 

reclaimed (i.e., reclaimable disturbance) is disclosed in the surface disturbance summary tables in 

recognition of the fact that the BLM would require the project proponents to reclaim unused disturbance 

during project operation. The disturbances listed in Table 2.4-1 are additional to the existing disturbance as 

well as to disturbance associated with each of the action alternatives discussed below. 

Table 2.4-1 No Action Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Roads 

Access Roads1 276 miles 45 feet 1,503 

Well Pads 

New Single Well Pads 1,102 each 2.5 acres 2,755 

Twinned Well Pads (Additional Disturbance) 0 each 0.2 acres 0 

Multi-well Pads (Additional Disturbance) 0 each 0.2 acres 0 

Well Pad Subtotal 1,102 each 2,755 

Construction/Production Facilities 

Mancamps 0 each 5 acres 0 

Compressor Stations 6 each 20 acres 120 

Water Tank Batteries 8 each 3 acres 24 

DEIS 2-6 July 2010 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2.4-1 No Action Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Water Injection Facilities (Additional Disturbance) 0 each 0.2 acre 0 

Facilities Subtotal 144 

Linear Facilities 

Gas Gathering Pipelines – Common ROW 262 miles 0 feet 0 

Gas Gathering Pipelines – Cross-country 14 miles 20 feet 33 

Gas Transport Pipelines (Buried) 0 mile 75 feet 0 

Water Gathering Pipelines – Common ROW (Surface) 0 mile 0 feet 0 

Water Connecting Pipelines (Buried) 26 miles 75 feet 236 

Electric Power Lines 2.5 miles 100 feet 30 

Linear Facilities Subtotal 300 

No Action Alternative New Disturbance (acre) 4,702 

GNBPA New Disturbance (%) 2.9% 

Existing Surface Disturbance (acre) 7,766 

Total Surface Disturbance (acre) 12,468 

Total GNBPA Disturbed (%) 7.7% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable No Action New Surface Dist (acre) 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 5,020 

Reclaimable Surface Disturbance (%) 40% 

Reclaimable Surface Disturbance as % of GNBPA 3.1% 

1

 Assume access road length of 0.25 mile/well pad. 

2

 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear 

Facilities summarized in the table above. 

2.4.1 Field Development Plan and Schedule 

Planned natural gas development in the GNBPA includes those facilities described in the NEPA documents 

for the following previously approved development projects: 

• Bonanza EA; 

• Love Unit EA; 

• North Chapita EA; 

• River Bend Unit Infill EA; 

• Rock House EA; 

• West Bonanza EA; 

• Chapita Wells-Stagecoach EIS; and 

• Greater Deadman Bench EIS. 

Based on the foregoing documents and a review of information from UDOGM, the BLM has estimated 

1,102 wells remain to be drilled in addition to the 1,562 existing wells producing or shut in awaiting pipeline 

DEIS 2-7 July 2010 
 

connection in the GNBPA (as of October 2007). Figure 2.4-1 illustrates the distribution of the existing wells 

and conceptual locations of analyzed yet undrilled wells within the GNBPA as of October 2007. In addition 

to the 1,102 wells, supporting infrastructure also would be installed as disclosed in the above NEPA 

documents. 

2.4.2 Alternative-specific Activities 

Details regarding development activities specific to the No Action Alternative are described in the following 

subsections. 

2.4.2.1 Access Roads 

Access to 1,102 wellsites would require approximately 276 miles of access road. Based upon analysis of the 

existing road network in the area as of June 2006 (Figure 2.4-2), an average new access road length of 

0.25 mile per well pad has been estimated. 

2.4.2.2 Drilling and Completion of Vertical Wells 

Implementation of the No Action Alternative would result in the drilling, completion, and construction of 

associated production facilities for an estimated 1,102 wells analyzed under previous NEPA actions. All of 

the wells are assumed to be vertical wells drilled on individual well pads. At an estimated drilling rate of 

approximately 192 wells per year (current KMG rate), drilling activity in the GNBPA would continue for 5 to 

6 years. 

Approximately 2,270 acre-feet of water would be required to drill and complete the approved wells at an 

estimated 2.06 acre-feet per well, based on current water usage in the GNBPA. 

2.4.2.3 Gas Production and Distribution 

Approximately 276 miles of gas gathering pipeline would be installed on the surface to transport natural gas 

from wells to larger buried pipelines that connect to processing facilities. Approximately 262 miles 

(95 percent) of the natural gas gathering pipeline system would be placed in available access road ROWs. 

Any activity within or adjacent to a county road ROW would be done with the permission of and in 

coordination with the county. An additional 14 miles (5 percent) of the natural gas gathering system is 

expected to require cross-country routing outside of access road ROWs; cross-country routing would require 

a 20-foot ROW for construction. 

Six compression and natural gas processing facilities would be constructed for a total additional 

96,600 horsepower (hp) of compression. Approximately half of this additional compression would be gas 

fired and half would be electrically driven. Each site would require approximately 20 acres for the life of the 

facility. 

The No Action Alternative would include the installation of an additional 2.5 miles of overhead electric power 

lines to provide power to compression facilities and pumps at water disposal facilities. The power lines 

would be 35-kilovolt (kV) distribution lines originating from an existing 32-mile power grid. The power lines 

would be installed within a 100-foot-wide ROW. 

2.4.2.4 Water Requirements 

Under the No Action Alternative, fresh water used for well drilling and completion purposes would continue 

to be obtained from existing commercial water supply sources in or near the GNBPA. Withdrawals would be 

made from suppliers that hold existing groundwater or surface water rights permits through the Utah 

Division of Water Rights. Assuming that water recycling satisfies half the demand, approximately 225 acrefeet per year would be needed. This primarily would be withdrawn from groundwater sources involving four 

potential suppliers: Target Trucking (permit 43 -1088), RN Industries (permits 49-164, 49-2166, and 

49-2231), Buggsey's Water Service (permit 49-22801), and Dalbo Water Services (probably involving 

DEIS 2-8 July 2010 
32 

8 7 

Green River 

Willow 

Creek 

Duchesne River 

21 22 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23

30 29 28 23 

28	 25 30 29 28 27 26 27 26

8-T4-R3 4-T8-R24 31 

33 

6 

32

8-T5-R30

5 

5	 0 

36 31 32 33 34 35

33 34 35 35 36 31 32 33 34 35 36 31 32 

27	 28 27 26 25 30 29 28 28 27 26 25 30 29

26 25 30 29 4-T8-R21	 4-T8-R22

4-T8-R20 4-T8-R23
 

33 34 

33 34 36 31 32 35 

Uint

Area Coun

ah

ty 

Detail Utah	 

of

4 3 

1 6 5 4 3 2 1 6 

6 5 4 3 2 1 6 5 4 3 2 

5 4 3 2 

2 1 

6 5 

11 12 7 8 9 10 11

11 12 7 8 9 10

7 8 9 10 11 12 7 8 9 10 

7 8 9 10 11 12 

16	 14 16 15 14 13 18 17 16 15 16 15 13 18 17 14 13 18 17 15 4-T9-R21	 4-T9-R22 4-T9-R23 13 18 17	 14

17 16 15 14 

18 4-T9-R20 22 23 20 21

19 23 24 19 20 21 22 23 24 19 

19 20 21 22 23 24 20 21 22 

22 23 24 4-T9-R24 19 20 21 

26 

28 27 26 25 30 29 28 27

30 29 28 27 26 25 30 29

30 29 28 27 26 25

30 29 28 27 26 25 

35 

32 33 34 35 36 31 32 33 34 

34 36 31 32 33 34 35 36 31

31 32 33 35 36 31 32 33 34 35 

1 6 5 4 3 2

6 5 4 3 2

4 3 2 1

2 1 6 5 4 3 2 1 6 5 5 4 3 6 

11 12 7 8 9 10 11 11 7 8 9 10 9 10 12 11 12 7 8

7 8 9 10

8 9 10 11 12 7 

13 18 17 16 15 14 13 17 16 15 14 18	 15 14 18 14 13 17 16
 

15 14 13 18 17 16 15
 4-T10-R24 18 17 16 

4-T10-R20 4-T10-R22 4-T10-R23 21 22

4-T10-R21 22 23 19 20 21 22 23 24 19 20

19 20 21 24

20 21 22 23 24

22 23 24 19 19 20 21 

29 28 26 25 30 29 28 27

25 30	 27 30 29 28 27 26

29 28 27 26 25 

30 29 28 27 26 25 30 

Existing and Approved Wells 

Named Streams and Rivers 

Township/Range 

Sections 

EIS Project Area 

31 32 33 34 35 

33 34

36 31 32 33 34 35 36 31 32 

31 32 33 34 35

36 36 31 32 33 34 35 

6 5 4 3 2 1 4 3 2 1 6 5 4 3 2 

3 2 1 6 5 

5 4 3 2 1 6 5 4 

7 8 9 10 11 

7 8 9 10 11 12 11 12 11 7 8 9 10

11 7 8 9 10 12

8 9 10 12 

16 15 14 4-T11-R22 4-T11-R23	 18 17 4-T11-R24 4-T11-R20 4-T11-R21	 16 15 14 13 18 17 16 15 14 13

18	 14 13 18 17 17 17 16 15 14 13	 16 15 

23 19 20 21 22 

23 24 19 20 21 22 23 24

19	 24 19 20 21 22

20 21 22 23 20 21 22 23 24 

28 26 29 27 30 26 25 30 29 28 27 26 25 30 29 28 27 26 25

29 28 27 26 25 30 29 28 27 

31 32 33 34 35 

1 0.5 0 1 2 

Scale in Miles 

2 1.5 1 0.5 0 2 

Scale in Kilometers

Greater Natural

Area Gas Developmen

Buttes

t

Project EIS 

Figure 2.4-1
 

No Action Alternative
 

2-9

Tuesday, February 10, 2009 7:31:36 AM

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Glen Bench Road 

(3260) 

Fidlar Road 

(3440) 

Seven Sisters Road 

(3420) 

Bitter Creek Road 

Seven Sisters Road 

(3420) 

Seven Sisters Road

(3420) 

Seep Ridge Road 

Seep Ridge Road 

Glen Bench Road 

(3260) 

Bitter Creek Road 

East Bench Road 

Love Road 

West Sand Wash Road 

West Fork Cottonwood 

Wash Road 

West Fork Cottonwood 

Wash Road 

Hatch Reservoir Road 

White River South Road 

NB. PIPELINE 

NB. PIPELINE 

Coyote Wash Road 

West Sand Wash Road 

Chipeta Grove Road 

Glen Bench Cutoff 

Kennedy Wash Road 

Chipeta Grove Road 

Archy Bench Road 

White River 

Coyote Wash Road 

South Road 

Middle Road 

Middle Road 

East Bench Road 

West Sand Wash Road 

Island Gas Field Road 

31 

32 

5 

6 32 

18 

30 

Green River 

Willow 

Creek 

Duchesne River 

20 22 23 24 19 20 21 22 23 24 19 20 21 22 23 21 22 24 19 21 28 23 

28 29 28 27 26 

30 29 

25 30 27 25 28 27 26 25 30 29 28 27 26 26 30 29 8-T4-R3
 28 27 26 25 30 29 4-T8-R21 4-T8-R24 4-T8-R23 33 4-T8-R22 0 4-T8-R20 Uintah 33 35 34 36 

36 

34 35 36 31 32 Area County 32 33 36 31 32 33 34 35 33 31 32 34 35 31 of

88 33 34 35 45 Detail Utah 4 

05 8-T5-R3 4 3 2 3 2 1 6 5 1 6 5 3 2 6 5 4 2 1 2 5 4 3 1 6

11 12 8 9 10 11 7 

7 8 4 3 

6 5 

9 11 12 11 7 8 9 10 12 7 8 

10 

7 8 9 11 12 7 8 9 10 10 

16 Named Streams and Rivers 17 16 14 16 15 15

4-T9-R23
 16 14 18 15 18 18 17 

14 17 14 13 13 4-T9-R22 15 13 Township/Range 4-T9-R21 18 13 17 17 16 15 14 

24 

Sections

4-T9-R20 20 21 22 23 EIS Project Area 24 19 22 23 19 23 19 20 21 20 21 22 24 

19 20 21 22 23 4-T9-R24 Trunk Roads 22 23 24 19 20 21 

Other Roads 26 

26 25 30 29 28 27 28 27 30 28 27 26 25 30 29 88 27 26 25 29 30 29 28 27 26 25 30 29 28 

31 32 33 

35 

35 36 34 34 35 32 33 32 34 35 36 31 36 31 33 34 31 32 33 31 32 33 34 36 35 

3 

2 5 4 3 2 1 6 2 1 6 5 4 

6 5 4 3 2 1 4 3 1 6 5 3 2 5 4 6 

12 7 8 9 10 11 11 9 10 11 7 8 12 12 8 9 10 11 7

11 

8 9 10 12 7 10 8 9 7 Glen Bench Road 

(3260) 18 13 18 17 16 15 14 13 17 16 15 14 18 16 15 14 4-T10-R24 13 17 

14 13 17 15 18 14 18 17 16 15 16 

4-T10-R23 4-T10-R20 4-T10-R21 22 24 19 20 21 21 22 23 23 19 21 22 24 19 20 20 24 23 24 22 20 21 4-T10-R22 22 23 19 19 20 21 

28 27 26 28 25 30 29 Bitter Creek 29 27 26 25 30 

27 

35 

30 27 28 Cutoff 29 25 29 28 26 25 30 29 28 27 26 

32 33 34 36 31 32 33 34 35 36 31 

1 

Archy Bench Road 

33 34 35 31 32 31 36 36 32 33 34 31 32 33 34 35 Love Road 

6 5 

3 2 6 5 4 4 1 3 2 3 2 

8 

Seep Ridge Road 

4 1012 0.5 5 2 1 6 6 5 4 3 4 3 2 1 Scale in Miles 

2 0 1.5 1 0.5 2

Scale in Kilometers 9 11 10 11 7 8 

7 8 10 12 9 11 12 Greater Natural Buttes 

Love Road 

11 

14 

12 

13 

7 8 9 10 11 7 9 10 12 

18 17 16 

Area Gas Development 8 9 10 

16 Project EIS 4-T11-R22 4-T11-R23
 15 14 18 17 4-T11-R24 4-T11-R20
 15 14 13 18 17 16 15 14 13

18 17 4-T11-R21 17 16 15 14 13 16 15 

23 19 20 21 22

20 21 22 23 24 23 24 19 Figure 2.4-2 19 21 22 19 20 22 23 24 20 21 20 21 22 23 24 

Existing Access Roads 28 26 29 27 

27 25 30 29 28 30 27 26 25 30 29 28 27 26 25 27 26 25 30 29 28 26 

31 32 33 34 35 

29 28 

5 

2-10

Wednesday, March 12, 2008 9:48:50 AM 

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permits 49-2235, 49-2229, and/or 49-1399) (Utah Division of Water Rights 2009). Source water for 

Buggsey's Water Service includes both a groundwater point of diversion and a surface point of diversion on 

the Green River near Ouray, Utah (Utah Division of Water Rights 2009). Any remaining fresh water 

demands would be met by Green River withdrawals near Jensen, Utah, under an existing permit (49-225) 

held by the Deseret Generation and Transmission Cooperative. Any river withdrawals made through the 

cooperative likely would be small in total volume, and would be limited by the permitted maximum 

withdrawal rate of 15 cubic feet per second. 

2.4.2.5 Produced Water Disposal 

Eight water tank batteries at 3 acres each would be constructed for temporary storage of produced water. 

Approximately 26 miles of 4- to 12-inch, buried polypropylene pipe water flowlines would be installed within 

a 75-foot-wide ROW to transport produced water from new and existing storage facilities (tank batteries and 

existing evaporation ponds) to existing injection wells. 

Existing evaporation/recycle facilities would be used to allow produced water to evaporate or to be re-used 

in completion and drilling operations. Re-use of produced water during operations reduces the amount of 

water that would be obtained from other sources such as the White River or water wells. Re-use of 

produced water also would reduce the amount of residual waste water that would require re-injection or 

evaporation for disposal. Some of the produced water recycled from the ponds potentially would be used for 

hydraulic fracturing during completion operations, reducing the amount of water that would be injected or 

evaporated. Use of the existing evaporation ponds would reduce water trucking requirements within the 

GNBPA. 

Transport of produced water to disposal facilities would require approximately 32,218 truck trips annually 

over an estimated average round trip transport distance of approximately 10 miles. This estimate assumes 

an average 100-barrel (bbl) capacity water truck and estimated annual produced water from the No Action 

Alternative wells of 415 acre-feet. Based on these assumptions, the average daily produced water would be 

approximately 8,700 bbl of water per day (BWPD). Existing disposal capacity includes 7,500 BWPD in 

evaporation ponds and 18,200 BWPD in active disposal wells, for a total capacity of 25,700 BWPD. 

2.5 Field Development Activities Common to All Action Alternatives 

Project development within the GNBPA would result in the construction of new roads and use of existing 

roads. Equipment required by most wells would include a gas gathering pipeline, a separator, gas meter, 

produced water tanks, and liquid hydrocarbon storage tanks. Gas would be transported via pipeline to 

centralized compression and treatment facilities. Produced water would be transported by truck and/or 

pipeline to KMG-operated produced water disposal wells or to existing KMG or commercially owned 

evaporation ponds or disposal wells. To minimize new disturbance, KMG would utilize the existing ancillary 

facility infrastructure within the GNBPA, where possible, including gas compression facilities, power lines, 

water disposal and treatment facilities, and gas gathering pipelines. 

The following sections summarize general pre-construction, construction, drilling and completion operations, 

production and maintenance operations, and abandonment and reclamation procedures common to all 

action alternatives. KMG has committed to AECPMs that would apply to project development unless the 

measures are superseded or modified by site-specific COAs. In general, KMG would: 

• Comply with all applicable federal, state, county, and BLM regulations (including any applicable 

interagency memorandums of understanding) for all operations associated with the project; 

•	 Adhere to all lease stipulations and COAs; and 

•	 Conduct its operations in accordance with the standards contained in its Surface Use Plan of 

Operations. 

DEIS	 2-11 July 2010 
 

Key ACEPMs are provided in Appendix A. Detailed numbers and summaries of anticipated surface 

disturbance associated with each action alternative are presented within each action alternative section. 

2.5.1 Pre-construction Activities 

2.5.1.1 Surveying and Notice of Staking or Application for Permit to Drill 

Prior to the start of construction activities on BLM-managed lands, KMG would: 

•	 Submit site-specific applications (NOS/APD/Sundry Notice/ROW application); 

•	 Survey and stake the location; 

•	 Participate in an on-site inspection; 

•	 Submit detailed construction plans, as needed; and 

•	 Perform cultural resource, paleontological, biological (including threatened and endangered plant 

and animal species), and/or other surveys, as necessary. 

For wells on BLM-managed land, KMG must obtain a permit from the BLM before surface disturbing 

activities can take place. To initiate the permitting process, KMG would file either a NOS or an APD with the 

BLM Vernal Field Office, which would process the application to ensure that it meets applicable 

requirements. For wells on split estate lands, KMG would follow the requirements of Section VI, Onshore Oil 

and Gas Order No. 1, for notifying and obtaining an access agreement with the surface owner. 

A complete APD normally consists of a Surface Use Plan, Drilling Plan, evidence of bond coverage, and 

other information that may be required by the BLM in compliance with Onshore Oil and Gas Order No. 1. A 

Surface Use Plan contains information describing construction operations, access, water supply, well site 

layout, production facilities, waste disposal, and restoration/revegetation or reclamation associated with the 

site-specific well development proposal. The Drilling Plan typically includes information describing the 

technical drilling aspects of the specific proposal, safety specifications, and subsurface resource protection. 

Determination of the suitability of KMG’s design, construction techniques, and procedures would be made 

by the SMA during the permitting process. 

2.5.1.2 Pre-construction Activities and Construction Initiation 

Prior to construction and APD approval, the SMA would conduct on-site inspections to assess potential 

impacts and recommend additional methods to mitigate impacts, if warranted and viable. The SMA may 

impose the mitigation measures as COAs to the APD. These additional environmental protection measures 

could address all aspects of oil and gas development, including construction, drilling, production, 

reclamation, and abandonment. The SMA would notify KMG of a date, time, and place to meet to perform 

an on-site inspection. Survey stakes would be used to indicate the orientation of the well pad and flagging 

would be used to indicate the routing of access roads, pipelines, or other linear features. 

Changes or modifications would be made during the inspection if needed to avoid or mitigate impacts to 

natural and cultural resources. Cut and fill and construction issues also would be addressed, as necessary. 

For wells on BLM-managed land, provisions of 43 CFR 3101.1-2 and the BLM standard lease 

(Form 3100-11) allow for the relocation of the proposed well up to 200 meters and a delay in operations of 

up to 60 days. Requirements for local notices to leasees may include other protective measures. 

2.5.2 Access Roads 

Primary access to the GNBPA would be via Glen Bench Road, State Highway 45, and State Highway 88. 

Access within the GNBPA would be via the existing road network, which consists of arterial roads and 

individual well access roads. County roads within the GNBPA include Class 1-B gravel roads (Seven Sisters 

DEIS	 2-12 July 2010 
 

 

 

Road, Fidlar Road, Bitter Creek Road, and Seep Ridge Road) and a Class 1-B paved and graveled road 

(Glen Bench Road) (Figure 2.4-2). 

New roads would be constructed where needed for vehicle access. Road design and construction 

specifications on BLM-managed lands would conform to Gold Book standards. Site-specific requirements 

would be incorporated on a case-by-case basis through COAs attached to the APD or ROW grant. 

KMG has developed a conceptual Transportation Plan to support oil and gas development to be 

implemented by the Proposed Action (Appendix C). The exact location of well access roads would be 

determined at the time of the on-site inspection with the appropriate SMA. New roads would cross federal, 

state, Tribal, and private surfaces. The plan includes measures to minimize resource conflicts and 

development costs. The plan objectives would: 

•	 Maximize use of the existing road system; 

•	 Facilitate identification of roads not needed for operations; 

•	 Identify main arteries and if they are designed to a standard that would accommodate all weather 

and the volume of traffic anticipated; 

•	 Minimize the number of loop roads; 

•	 Minimize the crossing of side slopes greater than 40 percent; 

•	 Minimize profile grades; 

•	 Minimize drainage crossings, with emphasis placed on drainages with potentially large runoff flows 

and floodplains; and 

•	 Design all roads to an appropriate level, no higher than necessary. 

New roads would be built and maintained to provide year-round access, as necessary. Bulldozers, graders, 

and other types of heavy equipment would be used to construct and maintain the road system. 

Existing roads that require upgrading would meet standards appropriate to the anticipated traffic flow and all 

weather road requirements. Upgrading may include ditching, drainage, graveling, crowning, and capping the 

roadbed as necessary to provide a well constructed, safe roadway. Construction or upgrading would not 

occur during muddy conditions. Where operations would involve the use of county roads or where a project 

road would connect to a county road, KMG would coordinate activities with the county road department. 

Running surfaces of new roads are typically 18 feet wide. Access road disturbance has been calculated 

using a maximum disturbed width of 45 feet, which corresponds to a typical road ROW. The amount of 

surface disturbance resulting from road construction would depend upon the number of new well pads. 

2.5.3 Drilling and Completion of Vertical Wells 

2.5.3.1 Well Pad Construction 

Well pads would be constructed to create a level surface for drilling equipment utilizing the native materials 

present at the site. Mineral materials from outside the GNBPA would not be required. Locations would be 

leveled by balancing cut and fill areas. Construction practices may include excavation or blasting to achieve 

a level pad. Blasting is normally required when bedrock is near the surface. Prior to blasting, the appropriate 

agency would be notified, and operations would be conducted according to applicable safety standards. 

Topsoil and native vegetation would be removed and separately stockpiled for use in the reclamation 

process. 

The initial average well pad size for a single well would be approximately 2.5 acres, based on average 

dimensions of 310 by 350 feet. If productive, the reserve pit and all portions of the well pad not needed for 

DEIS	 2-13 July 2010 
 

routine operations would be reclaimed to reduce surface disturbance to an average of 2 acres for the life of 

a well. KMG would attempt interim reclamation of linear features, well pads, etc., but, due to the difficulty in 

achieving timely successful interim reclamation, this EIS assumes initial disturbance would be long-term 

disturbance. Locations for twin wells (i.e., a second vertical well drilled from the same pad to a deeper 

horizon) would increase disturbance by 0.5 acre for the additional well on a single pad. If the well were not 

productive, surface reclamation would commence upon notice of intent to abandon the last well on the pad. 

2.5.3.2 Well Drilling 

Drilling operations would be conducted in compliance with all applicable local rules and regulations including 

Federal Oil and Gas Onshore Orders and UDOGM rules and regulations. KMG anticipates that multiple 

drilling rigs would be operating in the GNBPA to achieve its production objectives. Each rig is expected to be 

able to drill an average of approximately 24 wells each year. 

Following construction of the access road and well pad, a drilling rig would be transported to the wellsite and 

erected on the well pad. Wells would be drilled utilizing a conventional mobile drilling rig. The rig would be 

erected at the drill site after the conductor pipe has been set. Drilling operations typically would consist of 

drilling surface hole, "running" (inserting into the hole) and cementing in place the surface casing below all 

usable aquifers in the area, drilling a deeper and smaller diameter production hole, and running and 

cementing production casing. Intermediate casing, which would be used after setting surface casing and 

prior to drilling the production hole, also would be run when necessary. The rig would then be dismantled 

and demobilized from the location. 

The quantity and composition of drilling fluids would be determined on a well-by-well basis. Drilling fluids 

typically consist of water or fresh water-based mud. Wells would utilize an open-loop circulation system with 

a reserve pit. Drilling fluids and cuttings would be contained entirely within the reserve pit. No hazardous 

substances would be placed in the reserve pit. Reserve pits would be constructed in accordance with 

applicable regulations and Gold Book specifications. The reserve pit would be constructed on the location 

and would not be located within natural drainages, where a flood hazard exists, or where surface runoff 

would destroy or damage the pit walls. If hydrocarbons enter a reserve pit, they would be removed as soon 

as possible in accordance with 43 CFR 3162.7-1. After drilling and completion operations are finished, the 

liquid contents of a reserve pit would be recycled for use in completing a subsequent well or removed and 

disposed of at an approved waste facility. Drill cuttings would be buried in the reserve pit. The reserve pit 

would be fenced on three sides during drilling operations and on the fourth side when the rig moves off the 

location. Fences would be constructed according to SMA requirements or as described in the Gold Book. 

During drilling operations, a blow out preventer would be installed on the surface casing to provide 

protection against uncontrolled entry of reservoir fluids into the wellbore should reservoir pressures exceed 

the hydrostatic pressure of the wellbore fluid. In addition, a flow control manifold consisting of manual and 

hydraulically operated valves would be installed at ground level. All pressure control devices would comply 

with the provisions of Onshore Order No. 2. 

Prior to setting casing, open hole well logs may be run to evaluate a well’s production potential. If the 

evaluation concludes that sufficient oil and/or gas is present and recoverable, then steel production casing 

would be run and cemented in place in accordance with the well design, as specified in the approved APD 

and COAs. The casing and cementing program would be designed to isolate and protect shallower 

formations encountered in the wellbore and to prohibit pressure communication or fluid migration between 

zones. The cement would protect the well by preventing formation pressure from damaging the casing and 

retarding corrosion by minimizing contact between the casing and formation fluids. Certain cased-hole 

evaluation logs also may be run subsequent to setting and cementing production casing. 

DEIS 2-14 July 2010 
 

2.5.3.3 Well Completion 

After a well is drilled and production casing is set, a completion unit would move on location to perforate and 

stimulate the reservoir. The casing would be perforated across the productive zones, followed by a 

stimulation treatment of the formation to enhance its transmissibility of oil and gas. 

Hydraulic fracture stimulation is required on the majority of wells in the GNBPA in order to enhance 

productivity and is the typical stimulation measure used. A water/sand slurry would be used with gels and 

other non-toxic chemical additives to ensure the quality of the fracture fluid. Fluid would be pumped down 

the well through perforations in the casing and into the formation. Pumping pressures would be increased to 

the point at which fractures radiate outward from the perforations into the target formation and the slurry 

flows rapidly into the fractures. The sand serves as a proppant to keep the created fracture open, thereby 

allowing reservoir fluids to move more readily into the well. Hydraulic fracturing is a well understood and 

commonly employed technology used on potentially productive reservoirs at depths below usable aquifers. 

2.5.3.4 Water Requirements 

Water would be used during drilling and completion operations and for dust abatement on access roads, as 

needed. Produced water, oil, and other byproducts would not be applied to roads or well pads for control of 

dust or weeds. 

An average of approximately 16,000 bbls (2.06 acre-feet) of water would be utilized during drilling and 

completion operations for each well. KMG has begun to recycle produced water in the field to be used for 

new well completions. If this operating practice proves successful, the fresh water requirements for well 

completions would be reduced. KMG anticipates using recycled produced water in its new completions. 

Fresh water used for drilling and completion purposes would be obtained from commercial water supply 

sources. These sources would consist of both groundwater from wells and surface withdrawals from the 

Green River. Withdrawals would be made from suppliers that hold existing water rights permits through the 

Utah Division of Water Rights. 

Groundwater would be obtained from Target Trucking (permit 43-1088), RN Industries (“RNI Water Plant”; 

permits 49-1645, 49-2166, and 49-2231), Buggsey’s Water Service (permit 49-22801), and Dalbo Water 

Services (probably permits 49-2235, 49-2229 and/or 49-1399). Source water for Buggsey’s Water Service 

includes both an underground point of diversion (a well) and a surface point of diversion (the Green River 

near Ouray, Utah) (Utah Division of Water Rights 2009). Based on estimates from KMG and additional 

estimates of the supply available from Dalbo Water Services wells, approximately 225 acre-feet per year 

would be obtained from these four sources combined. All of these points of diversion are located in Ouray, 

Utah, or the general vicinity. 

As needed, all remaining fresh water would be obtained through the Deseret Generation and Transmission 

Cooperative. That organization holds rights to surface withdrawals from the Green River approximately 

3 miles south of Jensen, Utah (permit 49-225) (Utah Division of Water Rights 2009). 

2.5.3.5 Ancillary Facilities 

Mancamps to house rig crews near the working rigs likely would be required in addition to those existing in 

the GNBPA. Each mancamp would accommodate a single rig crew. KMG would locate one mancamp on 

federal land (Section 3, T10S, R21E) and a second mancamp on state land. Each mancamp would require 

approximately 5 acres and would be reclaimed when no longer needed. 

2.5.3.6 Equipment and Manpower Requirements 

Four to six men would comprise the construction crew for each access road and well pad. They would 

access the location using an average of three light trucks. Two to three pieces of heavy equipment, such as 

DEIS 2-15 July 2010 
 

bulldozers and motor graders, would be used to perform the earth-moving operations. Both the access road 

and well pad typically can be constructed within 7 to 14 days. 

An average of 10 persons would be required for drilling and completion operations, although the actual 

number would range from approximately 5 to 50 people. An average of eight vehicles would be used for 

access to each location daily. 

Duration of drilling operations on a given well can vary depending on depth and conditions encountered 

while drilling, but duration on location in the GNBPA can range from approximately 8 to 50 days. Completion 

operations typically require approximately 7 days per formation completed. 

2.5.4 Gas Production, Distribution, and Maintenance 

2.5.4.1 Wellsite Facilities 

Well production facilities would include the well head, valves, piping, and a combination separator/gas meter 

that would be housed in a small building on each location. Each well pad in the Natural Buttes or Love units 

within the GNBPA would contain a single 300-bbl combination tank to contain produced water and 

condensate. Outside of the federal units but within the GNBPA, each location would contain two 300-bbl 

tanks, one each for produced water and liquid hydrocarbons. In addition, one or more 500-gallon (or 

smaller) chemical tanks containing scale/corrosion inhibitor, methanol, or soap and a plunger lift would be 

located on all wellsites. 

2.5.4.2 Gas Pipelines 

Steel gathering pipelines with a 3, 4, 6, 8, or 10-inch outside diameter would be installed on the ground 

surface to transport the produced gas from the wells to the larger (more than 10 inches) lateral pipelines. 

Burying pipelines throughout much of the GNBPA can be challenging due to the presence of shallow 

bedrock and difficult reclamation conditions related to shallow, saline soils. However, KMG continuously 

evaluates the practicality of burying natural gas pipelines on a case-by-case basis and has found that it 

generally is practical to bury lateral lines when collecting gas from four wells or more on a multi-well pad. For 

purposes of this EIS analysis, it is assumed that KMG would not bury natural gas gathering pipelines that 

are 10 inches or less in diameter. KMG would utilize existing ROWs and road disturbances as much as 

possible when burying new pipelines. 

The applicant has committed to burying new pipelines within 100-year floodplains (Appendix A). In addition, 

pipeline crossings of streams would conform to the Hydraulic Considerations for Pipelines Crossing Stream 

Channels as outlined in the BLM Vernal RMP (BLM 2008b). Pipeline segments would be welded or 

zaplocked together on disturbed areas in or near the location, whenever possible, and dragged into place. 

New gathering pipelines would be installed parallel to and within approximately 10 feet of access road 

running surfaces unless precluded by topography, by county prohibition where installed adjacent to 

county-maintained roads, or by gathering system constraints. Surface gathering lines would be buried where 

they intersect with access roads. The exact location of pipelines would be determined at the time of the 

on-site inspection with the appropriate SMA. Ramps across the surface lines would be used where 

necessary to allow the periodic crossing of surface gathering lines. 

The 27-foot portion of access road ROWs outside the 18-foot road running surface would be used for 

routing surface natural gas gathering pipelines. The surface area within a road ROW but outside of a road’s 

running surface would be re-vegetated after gathering line construction is complete, although reclamation is 

recognized to be difficult in the arid environment of the GNBPA. In addition, some cross-country routing of 

surface gathering pipeline may be required that would result in disturbance to a 20-foot-wide pipeline ROW. 

All areas within those cross-country ROWs would be re-vegetated after gathering line construction. 

Drilling the proposed wells may require the installation of larger buried pipelines to transport natural gas to 

processing facilities. Construction of larger-diameter (larger than 10 inches) natural gas pipelines would 

DEIS 2-16 July 2010 
 

 

 

 

 

 

 

require temporary use of a 75-foot-wide construction corridor. The larger buried pipelines would be located 

within existing pipeline ROWs or routed adjacent to roads as much as possible. Where practical, the 75-foot 

width would include the actual road surface. Pipe segments would be welded into longer sections adjacent 

to a trench and buried. Construction and installation of a buried pipeline would result in additional surface 

disturbance. After the pipe is buried, the construction corridor and ROW would be reclaimed. 

2.5.4.3 Gas Compression and Processing 

Natural gas would be transported to existing facilities for compression, treatment, processing, and sales gas 

compression. New gas-powered compressors would be muffled and housed to decrease the audible noise 

level. Gas would be transported from the wellhead via gathering pipelines to field compressor stations, 

where the gas would be compressed, to the Chapita central processing plant in Section 15, T9S, R22E, 

then further compressed for delivery to interstate pipelines operated by Questar, Northwest Pipeline, 

Wyoming Interstate Company, Colorado Interstate Gas, or others. 

KMG would install only low emission dehydrators at existing and future compressor stations to eliminate 

hazardous air pollutants (HAPs) that may otherwise result. Additional dehydration is performed at the 

existing processing facilities, including the Chapita Plant, Bridge Station, Ouray, and Cottonwood. KMG also 

would install control devices and implement procedures to reduce emission of air pollutants during drilling, 

completion, production, and transportation activities. 

2.5.4.4 Electrical Power Requirements 

Additional overhead electric power lines may be installed to serve produced water disposal wells and 

proposed compression. Either natural gas-driven generators or natural gas engines would be used initially 

to supply power to the injection pumps at the proposed produced water disposal wells. Overhead electric 

lines may be subsequently installed where practical to provide power to the pumps, replacing the natural 

gas powered compressor engines. KMG anticipates an approximately 50/50 split between electric powered 

and natural gas powered compressor engines. 

2.5.4.5 Normal Maintenance 

New wells would typically be visited daily for 2 to 3 weeks after completion, depending upon well 

performance. During this time, the new well would be visited once by a "pumper" (oilfield maintenance 

worker) and by 3 to 4 water trucks daily. Visits to each well would be reduced to approximately three times a 

week by one pumper and one water truck daily for the life of a well. After initial completion, wellsite telemetry 

would be installed to reduce the number of trips to a well by a pumper; however, this reduction was not 

quantified for the analysis in this EIS. Surface pipelines would be visually inspected on a regular basis. 

Maintenance of non-county roads within the GNBPA during drilling and construction would be the 

responsibility of KMG and other operators, as appropriate, and would be performed consistent with SMA 

specifications. During the duration of the project, KMG/operators would monitor the project roads and 

perform appropriate repairs. Repairs may be necessary to correct excessive soil movement, rutting, and/or 

damage to cattleguards, gates, or fences. 

2.5.4.6 Workovers 

Periodically, a workover on a well may be required. A workover uses a unit similar to a completion rig to 

perform a variety of maintenance procedures and keep the well operating as efficiently as possible. 

Workovers can include repairs to the wellbore equipment (casing, tubing, etc.), the well head, or the 

producing formation itself. These repairs generally occur during daylight hours and are typically of short 

duration. The typical workover would require approximately 3 days; however, workover operations can 

range from 1 to 10 days, with a small number requiring more than 10 days. Workover operations may 

require 4 to 30 men, with average manpower requirements of 6 persons. The frequency for this type of work 

cannot be accurately projected since workovers vary well by well and depend on site-specific 

DEIS 2-17 July 2010 
 

 

 

 

 

 

 

 

circumstances. No additional surface disturbance would result from workover operations, and require no 

additional regulatory approvals. 

2.5.5 Produced Water Disposal 

Produced water may be confined to a lined pit for a period not to exceed 90 days after initial production, 

weather permitting. After the 90-day period, the produced water would be contained on the well pad in a 

tank prior to being transported by water hauling trucks or gathering pipelines to disposal facilities. Produced 

water would be disposed of via subsurface injection, into commercial produced water disposal ponds, into 

existing KMG-owned evaporation ponds, or would be used in subsequent completion and additional drilling 

operations. Water not evaporated in a particular pond or used for fracturing would be pumped via pipeline to 

either a disposal well for injection or to one of the other ponds. 

2.5.5.1 Water Disposal Wells and Injection Facilities 

Additional produced water disposal wells would likely be drilled in the GNBPA on existing well pads, or 

existing wellbores would be converted from natural gas production to disposal operations to minimize 

additional surface disturbance. The number of produced water disposal wells would depend upon the ability 

to obtain the necessary permits through the appropriate permitting authority and the number of additional 

wells drilled under a given alternative. Injection into disposal wells is KMG’s preferred method of produced 

water disposal. The Birds Nest aquifer, a unit in the Parachute Creek Member of the Green River Formation, 

would be the primary subsurface zone for injection of produced water. 

Injection disposal of produced water is a highly regulated activity. Underground injection wells used in 

conjunction with oil and gas production are referred to as Class II wells under the UIC program 

(Table 2.3-1). Class II wells can be used either for pressure maintenance to increase the efficiency of the 

recovery of oil and gas, or can be used for the disposal of liquid waste generated by oil and gas production 

operations that meets the definition of exploration and production waste exempt under the Resource 

Conservation and Recovery Act, Subpart D (mainly produced water). 

Permitting of Class II wells is regulated in Utah by the USEPA and the State of Utah. On statutorily defined 

“Indian Country” lands (18 USC 1151), the USEPA is the authorizing regulatory agency and the UDOGM 

regulates the UIC program on lands not designated as “Indian Country.” In the GNBPA, the USEPA 

regulates the UIC program. The permit process requires agency review of the application and a 30-day 

public comment period upon publication of notice of a draft permit. If there are no protests or objections to a 

pending application, it will be approved administratively. 

Once produced water injection commences, the operator must conduct tests or surveys and provide the 

agency with the results as required under the UIC program. The tests and data required include a step-rate 

test, a mechanical integrity test, a radioactive tracer survey, a temperature test on the injection well, and 

temperature surveys on nearby wells to document that injection wells meet construction requirements, 

which prevent migration of fluids into underground sources of drinking water. The regulating agency may 

require additional monitoring if necessary. As required under the UIC program, a monitoring plan will be 

included in all Birds Nest aquifer UIC permits approved by the USEPA in the GNBPA. The monitoring plan 

for existing injection operations will include the installation of five wells to monitor for potential changes in the 

aquifer water chemistry and hydrodynamics. 

2.5.5.2 Water Pipeline System 

KMG would install 4- to 12-inch buried polypropylene pipelines to interconnect all water management 

facilities including salt water disposal wells, evaporation/recycle ponds, and centralized tank batteries. 

These water pipelines would be buried to prevent freezing. These pipelines would facilitate water transport 

among the individual disposal sites during maintenance on either a disposal well or evaporation/recycle 

pond, providing a countermeasure and response mechanism if problems occur elsewhere in the water 

management system. The buried water pipelines would be located adjacent to existing roads or within 

DEIS 2-18 July 2010 
 

 

existing buried pipeline corridors, where possible. Construction would require a 75-foot construction ROW, 

which would be reclaimed as near as practical after pipeline installation as described in Section 2.5.7, 

Reclamation and Abandonment. 

Water gathering pipelines (between wells and disposal systems) would be considered to reduce traffic 

impacts from water trucking to disposal facilities. Three- to 6-inch steel and/or polypropylene pipeline could 

be installed in conjunction with (along side) the gas gathering pipelines. Surface installation within the 

45-foot construction width of the access road would result in no additional surface disturbance. KMG 

continuously evaluates the technical and economic viability of water gathering pipelines versus trucking. In 

general, KMG currently transports produced water by truck from areas that are remote from the centralized 

water collection system. On a case-by-case basis, KMG evaluates the economic feasibility of connecting 

remote areas to the centralized water collection system with pipelines and has connected several of these 

remote areas to the system. However, analysis for the EIS has assumed that all water transport between 

wells and disposal systems would be by truck. 

2.5.6 Hazardous Materials and Solid Waste 

A variety of chemicals, including lubricants, paints, and additives are used to drill, complete, and operate a 

well. Some of these substances may contain constituents that are hazardous. Hazardous materials can 

include some greases or lubricants, solvents, acids, paint, and herbicides, among others. These materials 

would not be stored at well locations although they may be kept in limited quantities on drilling sites and at 

production facilities for short periods of time. Transportation of the materials to the well location is regulated 

by the USDOT under 49 CFR, Parts 171–180. USDOT regulations pertain to the packing, container 

handling, labeling, vehicle placarding, and other safety aspects. 

None of the chemicals that would be used during drilling, completion, or production operations meet the 

criteria for being an acutely hazardous material/substance or meet the quantities criteria per the BLM 

Instruction Memorandum No. 93-344. Chemicals subject to reporting under Title III of the Superfund 

Amendments and Reauthorization Act (SARA) in quantities of 10,000 pounds or more would not be used, 

produced, stored, transported, or disposed of annually while drilling or completing a well in the GNBPA. In 

addition, extremely hazardous substances, as defined in 40 CFR 355, in threshold planning quantities, 

would not be used, produced, stored, transported, or disposed of while drilling or completing a well. 

Most wastes that would be generated at project locations are excluded from regulation by the Resource 

Conservation and Recovery Act under the exploration and production exemption in Subtitle C 

(40 CFR 261.4[b][5]) and are considered to be solid wastes. These wastes include those generated at the 

wellhead, through the production stream, and through the gas plant. Exempt wastes include produced 

water, production fluids such as drilling mud or well stimulation flowback, and contaminated soils. 

Any release of oil, gas, salt water, or other such fluids would be immediately cleaned up and removed to an 

approved disposal site. The spills would be reported to the AO and other appropriate authorities. KMG 

would develop and maintain site-specific Spill Prevention Control and Countermeasures Plans (SPCCPs) 

for each production facility in the GNBPA. An example site-specific SPCCP is provided in Appendix D. To 

satisfy SPCCP requirements, if storage facilities or tanks are constructed, they would be constructed in 

accordance with applicable regulations. 

Trash containers and portable toilets would be located on construction sites. Garbage, trash, and other 

waste materials would be collected in portable, self-contained, fully enclosed trash cages during 

construction, drilling, and completion operations and disposed of at an approved landfill. Trash would not be 

burned on location. Construction locations and wellsites would be cleaned of other debris and waste 

materials and removed from the location after drilling and completion operations. 

DEIS 2-19 July 2010 
 

 

 

2.5.7 Reclamation and Abandonment 

Reclamation of surface disturbance associated with the proposed project and alternatives would be 

implemented in accordance with the Green River District Reclamation Guidelines (BLM 2009a). The 

guidelines would apply to reclamation activities in the GNBPA and include measurable standards as well as 

the monitoring and reporting of compliance with the reclamation standards. KMG’s draft Reclamation Plan 

(Appendix E) generally is consistent with the Green River District Reclamation Guidelines and would be 

revised and finalized to develop a site-specific plan for each component of the project for which an APD 

and/or ROW application is submitted to the BLM. 

Surface disturbance associated with electric power line, surface pipeline, and buried pipeline installation 

would be reclaimed as soon as construction is complete according to the Reclamation Plan (Appendix E). 

Interim reclamation of the well pad would be performed as soon as practicable in accordance with 

applicable COAs after a well is drilled, completed, and put on production. Before reclamation begins on the 

reserve pit, it would be allowed to dry. After liquid removal, pits would be closed in accordance with surface 

management agency guidelines. The liner would be buried to a minimum of 4 feet below the surface. The pit 

and that portion of the location not needed for production operations would be reclaimed in accordance with 

applicable state regulations and Gold Book procedures. KMG would reseed the disturbed areas with 

mixtures specified by the applicable SMA or surface owner. Follow-up survey and treatment of weeds and 

invasive species would be conducted until reclamation is deemed to be successful and/or complete. 

Abandoned wellsites, roads, and other disturbed areas would be restored as near as practical to their 

original condition and in compliance with applicable federal, state, and Tribal regulations as well as the 

COAs. At the time of final abandonment, all surface equipment, including surface gathering pipelines, would 

be removed from the site. Cut and fill materials would be recontoured and topsoil would be replaced on the 

surface above the former location to blend the site with its natural surroundings. All surface disturbance 

would then be planted with a seed mixture of grass and plant species as specified by the appropriate SMA. 

Follow-up survey and treatment of weeds and invasive plant species would be conducted until reclamation 

is deemed to be successful and/or complete. 

At final abandonment of wells on BLM-managed lands, the casing would be cut off at the base of the cellar 

or 3 feet below the final restored ground level, whichever is deeper. KMG would cap the casing with a metal 

plate a minimum of 0.25 inch thick. The cap would be welded in place, and the well location and identity 

would be permanently inscribed on the cap. The cap would be constructed with a weep hole. 

2.6 Proposed Action Alternative 

A summary of surface disturbance associated with implementation of the Proposed Action Alternative is 

presented in Table 2.6-1. The disturbance indicated in Table 2.6-1 is new disturbance that would occur in 

addition to that from the No Action Alternative discussed in Section 2.4, No Action Alternative. 

Table 2.6-1 Proposed Action Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Roads 

Access Roads1 760 miles 45 feet 4,147 

Well Pads 

New Single Well Pads 3,041 each 2.5 acres 7,603 

Twinned Well Pads (Additional Disturbance) 634 each 0.2 acre 127 

DEIS 2-20 July 2010 
 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2.6-1 Proposed Action Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Multi-well Pads (Additional Disturbance) 0 each 0.2 acre 0 

Well Pad Subtotal 3,675 each 7,729 

Construction/Production Facilities 

Mancamps 2 each 5 acres 10 

Compressor Stations 2 each 20 acres 40 

Water Tank Batteries 2 each 3 acres 6 

Water Injection Facilities (Additional Disturbance) 15 each 0.2 acre 3 

Facilities Subtotal 59 

Linear Facilities 

Gas Gathering Pipelines - Common ROW 722 miles 0 feet 0 

Gas Gathering Pipelines - Cross-country 38 miles 20 feet 92 

Gas Transport Pipelines (Buried) 35 miles 75 feet 318 

Water Gathering Pipelines – Common ROW (Surface) 587 miles 0 feet 0 

Water Connecting Pipelines (Buried) 25 miles 75 feet 227 

Electric Power Lines 7 miles 100 feet 85 

Linear Facilities Subtotal 722 

Proposed Action New Disturbance (acre) 12,658 

GNBPA New Disturbance (%) 7.8% 

No Action Alternative New Disturbance (acre) 4,702 

Existing Surface Disturbance (acre) 7,766 

Total Surface Disturbance (acre) 25,125 

Total GNBPA Disturbed (%) 15.4% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable New Surface Disturbance (acre) 4,731 

Reclaimable No Action New Surface Dist (acre) 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 9,751 

Reclaimable Surface Disturbance (%) 39% 

Reclaimable Surface Disturbance as % of GNBPA 6.0% 

1

 Assume access road length of 0.25 mile/well pad. 

2

 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear 

Facilities summarized in the table above. 

2.6.1 Field Development Plan and Schedule 

KMG and other operators would drill a maximum of 3,675 new wellbores in addition to the existing 

producing wells and approved/permitted wells yet to be drilled in the GNBPA as discussed in Section 2.4, 

No Action Alternative. Figure 2.6-1 illustrates available locations for new wells at a 20-acre spacing. 

Although actual operations are subject to change as the project proceeds, KMG and other operators would 

drill additional wells at an average rate of approximately 358 wells per year for over 10 years or until the 

resource base is fully developed. The total number of wells that would be drilled during the life of the project 

or during any particular year would depend largely on factors outside of KMG’s control such as permit 

DEIS 2-21 July 2010 
 

 

 

 

 

approvals, production success, engineering technology, economic factors, commodity prices, rig availability, 

and lease stipulations. The productive life of each well is estimated to be approximately 30 to 50 years. 

KMG estimates that 3 percent of the drilled wellbores might be dry. A dry hole most commonly results from 

mechanical failure. 

2.6.2 Alternative-specific Activities 

2.6.2.1 Access Roads 

The Proposed Action Alternative would result in the drilling of up to 3,041 wells on new well pads. An 

additional 634 wells would be deepened recompletions or twins of existing wells from existing well pads. 

Access to 3,041 new well pads, assuming an average road length of approximately 0.25 mile per well pad, 

would require construction of 760 miles of new roads. 

2.6.2.2 Infill Drilling and Multiple-Well Pads 

Infill Drilling 

Infill drilling of vertical wells would be performed on 40-acre and 20-acre surface spacing throughout the 

GNBPA (i.e., with 16 to 32 surface well pads per section). KMG defines a 40-acre well pad as the first well 

pad located in a governmental 40-acre quarter-quarter section. A 20-acre pad is defined as the second well 

pad located in a 40-acre quarter-quarter section. Downhole well spacing would be based on KMG’s 

reservoir engineering evaluation on an on-going basis and would be site-dependent, potentially ranging from 

16 wells per section (40-acre spacing) to 64 wells per section (10-acre spacing) or more. A maximum of 

3,041 new well pads would be constructed to achieve the combined 40-acre and 20-acre surface spacing 

assuming vertical wells. This EIS assumes 20-acre spacing for all 3,041 new well pads, which represents 

the maximum surface disturbance. 

Mesaverde-only Completions 

Under the Proposed Action Alternative, KMG would plan to drill 634 completions to the Mesaverde 

Formation by either deepening an existing Wasatch wellbore or by drilling a twin well on an existing well 

pad. KMG expects most of the Mesaverde-only completions would be located in T8S-R21E, T9S-R21E, 

T9S-R22E, T10S-R21E, T10S-R22E, and T10S-R23E. 

Directional Drilling 

Portions of the GNBPA pose environmental constraints to drilling a vertical well from the surface. KMG has 

made a preliminary determination of those areas based upon the following constraining factors: 

•	 Topography, including steep slopes that preclude construction of a well pad for a vertically drilled 

well without major cuts-and-fills; 

•	 The viewshed (line-of-sight from the centerline up to 0.5 mile on either side of the river, whichever is 

less) of the White River corridor, outside of the Indian Trust Lands; and 

•	 Areas within 600 feet of the White River within the Indian Trust Lands. 

In areas where the gas resources in the reservoirs warrant a downhole spacing of less than 20 acres based 

on reservoir engineering evaluation, or in those areas where environmental constraints preclude vertical 

wells, KMG would test and attempt to utilize directional drilling technology to drill from nearby 20-acre or 

40-acre pads if such is technically and economically viable. It must be stressed that the decision of whether 

to drill an area to a downhole spacing less than 20 acres with directional wells would depend on KMG’s 

ability to drill and develop the gas resources in an economically and technically viable manner because of 

the economically marginal nature of wells in the GNBPA. Analysis of the Proposed Action Alternative 

assumes vertical wells would be drilled at all locations. 

DEIS	 2-22 July 2010 
31 

32 

5 

6 

32 

11 

7 7 8 

31 32 

River 

Willow 

Creek 

Duch esne River 

21 23 24 19 20 21 23 24 19 20 21 22 23 21 22 24 19 20 22 22 28 23 

28 29 28 27 26 

30 29 

25 30 27 25 28 27 26 25 30 29 28 27 26 26 30 29 8-T4-R3
 28 27 26 4-T8-R22 25 30 29 4-T8-R21
 4-T8-R24 4-T8-R23 33 

0 4-T8-R20 Uintah 33 35 34 36 31 32 Area County 33 34 35 31 32 34 35 36 31 32 33 34 35 36 of 33 36 31 32 35 33 34 Detail Utah

Gree

8-T5-R3 n 0

5 5 4 3 2 3 2 1 6 6 5 4 3 2 1 6 5 4 2 1 5 4 3 7 6 2 1 8 4 3 

6 5 

8 9 10 12 7 8 9 10 11 12 7 11 11 7 8 9 10 8 9 10 12

9 11 12 10 

17 16 15 14 13 18 17 4-T9-R21 16 15 14 13 18 17 4-T9-R22 16 15

14 13 18 17 4-T9-R23 15 

16 

14 13 18 17 16 15 14 Existing and Approved Wells 

Named Streams and Rivers 

Township/Range 

18 

19 20 21 

4-T9-R20 

22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 

4-T9-R24 

20 21 22 23 

Sections 

EIS Project Area 

Potential Locations for New Well Pads 

Proposed Action (2 pads per 40 acres) 

26 0 

30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 1 

2 

35 

31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 

6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 

18 17 16 15 14 13 18 17 16 15 14 13 18 17 16 15 14 13 18 17 16 15 14 13 18 

4-T10-R24 

17 16 15 14 

19 20 21 

4-T10-R20 

22 23 24 19 20 

4-T10-R21 

21 22 23 24 19 20 

4-T10-R22 

21 22 23 24 19 20 

4-T10-R23 

21 22 23 24 19 20 21 22 

30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 

33 34 31 32 32 33 34 35 36 

34 35 36 31 31 32 33 36 36 31 32 33 34 35 33 34 35 

5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

1012 0.5 

Scale in Miles 

202 1.5 1 0.5 

8 

17 

9 

16 

4-T11-R20 

11 10 

15 14

12 

13 

7 

18 

8 

17 4-T11-R21 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 

9 

16 

4-T11-R22 

11 10 

15 14

12 

13 

7 

18 

8 

17 

4-T11-R23 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 4-T11-R24 

9 10

15 16 

11 

14 

Scale in Kilometers 

Greater Natural Buttes 

Area Gas Development 

Project EIS 

20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 

19 20 21 22 23 

Figure 2.6-1 

29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 Proposed Action 

31 32 33 34 35 

2-23

Tuesday, February 10, 2009 7:30:34 AM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\Figures_Folder\PDEIS\Fig2_6-1_ProposedAction.mxd 
KMG currently anticipates that most of the wells with a downhole spacing of 20 acres or less would be 

located in portions of T9S-R21E, T9S-R22E, T10S-R22E, and T10S-R23E, or in areas of environmental 

constraints discussed above. However, KMG may drill wells with a downhole spacing of 20 acres or less at 

any location within the GNBPA, as production success is evaluated during the life of the project. The 

downhole density of wells within the GNBPA would reflect effective reservoir drainage patterns for the 

GNBPA. However, the surface density of the KMG well pads would not exceed 32 pads per section. 

KMG is currently using directional drilling techniques in development within the Bonanza Unit. Success in 

the Bonanza area in the east portion of the GNBPA does not necessarily indicate that directional drilling 

within the GNBPA would be successful. 

An average of 15 drilling rigs would be operating in the GNBPA over a 10-year period to drill the 3,675 wells 

proposed by KMG and other operators. Each rig would average 24 wells per year. These wells would be in 

addition to 1,102 wells authorized by prior NEPA as described under the No Action Alternative. 

Based on the need for 2.06 acre-feet per well, an estimated 7,571 acre-feet of fresh water would be required 

to drill and complete 3,675 wells or approximately 757 acre-feet each year for the projected 10-year drilling 

period. 

If a location is shared with more than one well and fluid volumes so warrant, additional tanks may be 

installed to provide increased storage capacity with no increase in well pad size/disturbance. KMG may 

install a single larger separator on pads that share more than one well. A berm capable of containing 

110 percent of the capacity of the largest tank would surround all tanks. All natural gas would be measured 

electronically, and KMG plans to install telemetry equipment to remotely operate and monitor wells, 

minimizing the number of wellsite visits. 

Two mancamps of approximately 5 acres each (10 total acres) would be located within the GNBPA. 

2.6.2.3 Gas Pipelines 

Approximately 760 miles of natural gas gathering pipeline would be installed to transport natural gas from 

project wells to larger buried pipelines that connect to processing facilities. Approximately 722 miles 

(95 percent) of the surface natural gas gathering pipeline system would be placed in available access road 

ROWs. Approximately 38 miles (5 percent) of the natural gas gathering system would require cross-country 

routing outside of access road ROWs; cross-country routing would require a 20-foot ROW for construction. 

Approximately 35 miles of larger-diameter, buried transport pipeline would be constructed within a 

75-foot-wide construction ROW that would overlap with other ROWs when possible. 

2.6.2.4 Gas Compression and Processing 

Two compression sites would be constructed to meet project compression needs within the GNBPA; each 

site would require approximately 20 acres for the life of the facility. These facilities would provide a total 

additional 79,000 hp of new compression; approximately half gas fired and half electrically driven. 

2.6.2.5 Electrical Power Requirements 

Under the Proposed Action Alternative, approximately 7.0 miles of overhead electric lines would be installed 

to provide power to the pumps at water disposal wellsites. The new power lines would be 35 kV distribution 

lines that would originate from the existing power grid. Pole mount transformers would be installed within 

500 feet of each point of use to obtain 480-volt power for the pumps. The power lines would be installed 

within a 100-foot ROW. Surface disturbance associated with electric power line installation within the ROW 

would be reclaimed as soon as construction is completed. 

DEIS 2-24 July 2010 
 

 

 

 

 

 

2.6.2.6 Water Disposal Facilities 

Up to 15 new water disposal wells would be drilled in the GNBPA on existing well pads or using existing well 

borings, located in Sections 19 through 36, T9S, R21E. Assuming an average disposal capacity of 

4,000 BWPD for each disposal well, the 15 new disposal wells would have a combined capacity of 

60,000 BWPD. Although estimated future water production is difficult to predict because of variable water 

saturation conditions as the gas reservoir is produced and depleted, KMG has estimated that approximately 

29,500 BWPD would be produced under the Proposed Action. Therefore, the proposed expansion of water 

disposal capacity would be more than adequate to accommodate the produced water from the project. 

Disposal well locations would be chosen based on suitable subsurface rock formation properties and water 

quality data. Each new water disposal well would add approximately 0.2 acre of new disturbance to an 

existing well pad, for a total maximum new surface disturbance of 3.0 acres. Several produced water tanks 

would be added to the sites of two of the more centrally located disposal wells. Additional tanks would add 

approximately 3.0 acres to the existing well pad for a total new surface disturbance of approximately 

6.0 acres. 

Approximately 25 miles of 4- to 12-inch, buried polypropolene water flowlines would be installed within a 

75-foot-wide ROW to interconnect all water management facilities including salt water disposal wells, 

existing evaporation/recycle ponds and centralized tank batteries. 

Currently, produced water is transported by truck from wellsite storage tanks to disposal facilities. The 

average round trip distance between storage tanks and disposal facilities is estimated to be approximately 

10 miles. Implementation of the Proposed Action would result in average annual additional produced water 

of approximately 10,744,414 bbls and would require approximately 107,444 annual disposal truck trips. 

To reduce air quality impacts associated with water disposal truck traffic, approximately 587 miles of 3- to 

6-inch polypropylene pipeline could be installed on the surface along side the surface natural gas gathering 

pipelines and within the 45-foot-wide access road ROWs. KMG would not implement construction of water 

pipelines on the ground surface until they identify a means of addressing the potential for freezing of water 

in the pipes. Installation of such surface pipelines would neither increase nor decrease the surface 

disturbance associated with the Proposed Action Alternative. 

2.7 Resource Protection Alternative 

A summary of surface disturbance associated with implementation of the Resource Protection Alternative is 

indicated in Table 2.7-1. The disturbance indicated in Table 2.7-1 is new disturbance that would occur in 

addition to that from the No Action Alternative. 

Table 2.7-1 Resource Protection Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Roads 

Access Roads1 594 miles 45 feet 3,238 

Well Pads 

New Single Well Pads 1,484 each 2.5 acres 3,710 

Twinned Well Pads (Additional Disturbance) 634 each 0.2 acre 127 

Multi-well Pads (Additional Disturbance) 1,557 each 0.2 acre 311 

Well Pad Subtotal 3,675 each 4,148 

DEIS 2-25 July 2010 
 

 

 

Table 2.7-1 Resource Protection Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility) 

Surface 

Disturbance 

(acres) 

Construction/Production Facilities 

Mancamps 2 each 5 acres 10 

Compressor Stations 2 each 20 acres 40 

Water Tank Batteries 2 each 3 acres 6 

Water Injection Facilities (Additional Disturbance) 15 each 0.2 acre 3 

Facilities Subtotal 59 

Linear Facilities 

Gas Gathering Pipelines - Common ROW 564 miles 0 feet 0 

Gas Gathering Pipelines - Cross-country 30 miles 20 feet 72 

Gas Transport Pipelines (Buried) 35 miles 75 feet 318 

Water Gathering Pipelines - Common ROW (Surface) 458 miles 0 feet 0 

Water Connecting Pipelines (Buried) 25 miles 75 feet 227 

Electric Power Lines 7 miles 100 feet 85 

Linear Facilities Subtotal 702 

Resource Protection Alternative New Disturbance( acre) 8,147 

GNBPA New Disturbance (%) 5.0% 

No Action Alternative New Disturbance (acre) 4,702 

Existing Surface Disturbance (acre) 7,766 

Total Surface Disturbance (acre) 20,615 

Total GNBPA Disturbed (%) 12.7% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable New Surface Disturbance (acre) 3,387 

Reclaimable No Action New Surface Dist (acre) 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 8,407 

Reclaimable Surface Disturbance (%) 41% 

Reclaimable Surface Disturbance as % of GNBPA 5.2% 

1

 Assume access road length of 0.4 mile/well pad for Resource Protection Alternative. 

2

 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear 

Facilities summarized in the table above. 

2.7.1 Field Development Plan and Schedule 

The Resource Protection Alternative would be similar to the Proposed Action, but places a limit on the 

maximum number of new well pad locations to 1 pad per 40 acres (maximum of 16 well pads per section). 

Figure 2.7-1 illustrates the available locations for new wells at a 40-acre spacing. Based on proposed 

activities identified earlier as common to all action alternatives, KMG and other operators would drill a 

maximum of 3,675 new wellbores in addition to the existing producing wells and approved/permitted wells 

yet to be drilled in the GNBPA. In order to complete 3,675 new wellbores from a reduced number of surface 

well pad locations, directional drilling techniques would need to be implemented by the operators. 

As discussed under the Proposed Action Alternative, KMG and other operators would drill additional wells at 

an average rate of approximately 358 wells per year over a period of 10 years or until the resource base is 

DEIS 2-26 July 2010 
 

 

fully developed, with a maximum total of 3,675 wellbores. The total number of wells drilled during the life of 

the project or during any particular year would depend largely on factors outside of KMG’s control. The 

estimated productive life of each well would be approximately 30 to 50 years, and 3 percent of the drilled 

wellbores might be dry principally due to mechanical failure. 

The drilling schedule, well drilling and completion parameters, equipment and manpower requirements, 

compressor stations, water disposal facilities, buried water and gas pipelines, electric power facilities, and 

ancillary facilities would be as discussed under the Proposed Action Alternative. 

The number of disturbance impacts associated with production facilities (mancamps, compressor stations, 

water tank batteries, and water disposal wells) as well as electrical power requirements is expected to be 

the same for the Resource Protection Alternatives as it would be for the Proposed Action Alternative. 

2.7.2 Alternative-specific Activities 

2.7.2.1 Access Roads 

Approximately 594 miles of new access road would be constructed to a maximum of 1,484 new well pads 

that would be available under this alternative. Because fewer new well pads would be constructed under the 

Resource Protection Alternative than under the Proposed Action Alternative, the average new access road 

length would be approximately 0.4 mile. 

2.7.2.2 Infill Drilling and Multiple-well Pads 

Infill drilling would be performed on 40-acre surface spacing (maximum of 16 well pads per section) 

throughout the GNBPA using vertical and directional drilling techniques. The location of the 40-acre spaced 

well pads would reflect avoidance of the following constraining factors: 

•	 Topography, including steep slopes that preclude construction of a well pad for a vertically drilled 

well without major cuts-and-fills; 

•	 The viewshed of the White River corridor (line-of-sight from the centerline up to 0.5 mile along both 

sides of the river), outside of the Indian Trust Lands; 

•	 Areas within 600 feet of the White River within the Indian Trust Lands; and 

•	 Areas within the 100-year floodplain of the White River, including Tribal Lands, and 5 miles up 

major tributaries. 

The Resource Protection Alternative would reduce impacts to other resources by limiting disturbance to a 

total of 16 well pad locations per section in comparison to as many as 32 well pad locations per section 

under the Proposed Action Alternative. 

As of October 2007, there were approximately 1,484 available 40-acre spacing locations for new well pads 

within the GNBPA. Under this alternative, it has been assumed that KMG would drill 634 Mesaverde-only 

completions from deepened recompletions or twinned wells on existing well pads as was the case for the 

Proposed Action. Limiting surface disturbance to 40-acre well pad spacing would reduce the number of 

possible new well pads from 3,041 to 1,484 under the Resource Protection Alternative. If full recovery of the 

natural gas resource requires the drilling of wellbores at a downhole spacing of 20 acres or less, then 

directional drilling techniques would be required under this alternative. Therefore, impact analysis of this 

alternative assumed 1,557 directionally drilled wellbores to establish the same number of wellbores (3,675) 

as the Proposed Action Alternative. 

DEIS	 2-27 July 2010 
31 

32 

5 

6 

32 

8 

0 

4 

5 

7 

Green River 

Willow 

Creek 

Duch esne River 

20 22 23 24 19 20 21 22 23 24 19 20 21 22 23 21 22 24 19 21 28 23 

28 29 28 27 26 

30 29 

25 30 27 25 28 27 26 25 30 29 28 27 26 26 30 29 8-T4-R3
 28 27 26 25 30 29 4-T8-R21 4-T8-R24 4-T8-R23 33 4-T8-R22 0 4-T8-R20 Uintah 33 35 34 36 31 32 Area County 33 34 35 31 32 34 35 36 31 32 33 34 35 36 of 33 36 31 32 35 33 34 Detail Utah 8-T5-R3
 1 6 5 4 3 2 4 3 2 1 6 5 2 1 6 5 4 3 3 2 5 4 3 2 1 6 

6 

7 

5 

8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 

18 

19 

30 

17 

20 

29 

4-T9-R20 

15 16 

22 21 

28 27

14 

23 

26 

13 

24 

25 

18 

19 

30 

17 

20 

29 

4-T9-R21 16 15

21 22

28 27

14 

23 

26 

13 

24 

25 

18 

19 

30 

17 

20 

29 

4-T9-R22 16 15

21 22

28 27

14 

23 

26 

13 

24 

25 

18 

19 

30 

17 

20 

29 

4-T9-R23 15 

16 

21 22

28 27

14 

23 

26 

13 

24 

25 

18 

19 

30 

4-T9-R24 

17 16

20 21

29 28

15 

22 

27 

14 

23 

26 

Existing and Approved Wells 

Named Streams and Rivers 

Township/Range 

Sections 

EIS Project Area 

Potential Locations for New Well Pads 

Resource Protection (1 pad per 40 acres) 

0 

1 

31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 

35 

6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 

18 

19 

17 

20 

16 

21 

4-T10-R20 

15 14

22 23

13 

24 

18 

19 

17 

20 

4-T10-R21 

16 15

21 22

14 

23 

13 

24 

18 

19 

17 

20 

4-T10-R22 

16 15

21 22

14 

23 

13 

24 

18 

19 

17 

20 

4-T10-R23 

16 15

21 22

14 

23 

13 

24 

18 

19 

4-T10-R24 

17 16

20 21

15 

22 

14 

30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 

33 34 31 32 32 33 34 35 36 

34 35 36 31 31 32 33 36 36 31 32 33 34 35 31 32 33 34 35 

5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

1012 0.5 

Scale in Miles 

2 0 1.5 1 0.5 2 

8 

17 

9 

16 

4-T11-R20 

11 10 

15 14

12 

13 

7 

18 

8 

17 4-T11-R21 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 

9 

16 

4-T11-R22 

11 10 

15 14

12 

13 

7 

18 

8 

17 

4-T11-R23 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 4-T11-R24 

9 10

15 16 

11 

14 

Scale in Kilometers 

Greater Natural Buttes 

Area Gas Development 

Project EIS 

19 20 21 22 23 Figure 2.7-1 

20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 

Resource Protection 

29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 Alternative 

31 32 33 34 35 

2-28

Wednesday, March 12, 2008 9:37:49 AM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\APDEIS_Figures\Fig2_7-1_ResourceProtectionAlternative.mxd 
 

 

 

 

 

 

 

 

 

2.7.2.3 Gas Pipelines 

As was the case with the Proposed Action Alternative, surface gas gathering pipelines are assumed to be 

co-located with access road ROWs approximately 95 percent of the time and would be installed crosscountry approximately 5 percent of the time. Under this alternative, approximately 564 miles of co-located 

and approximately 30 miles of cross-country surface pipeline would be installed. Approximately 35 miles of 

larger-diameter, buried transport pipeline would be constructed within a 75-foot-wide construction ROW that 

would overlap with other ROWs when possible. 

2.7.2.4 Water Disposal Facilities 

Produced water would be handled in the same manner as discussed under the Proposed Action Alternative. 

Because of differing numbers of well pads, wellbores, and road lengths, the volumes of produced water and 

amount of truck transport would differ. For this alternative, annual truck transport of produced water is 

estimated to be approximately 107,444 truckloads over an average of approximately 10 miles roundtrip, 

assuming an average truck capacity of 100 bbls. Average annual produced water from this alternative is 

estimated to be approximately 1,385 acre-feet. 

In the event that KMG were to proceed with construction of a water gathering pipeline system on the ground 

surface co-located within access road ROW disturbance, approximately 458 miles of surface pipeline could 

be constructed without increasing the surface disturbance. KMG would identify a solution to the issue of 

freeze protection prior to installation of aboveground water gathering pipelines. However, as with the 

Proposed Action Alternative, approximately 25 miles of buried connecting water flowlines within a 75-foot 

ROW would be needed to transport water to the water disposal wells. 

2.8 Optimal Recovery Alternative 

A summary of surface disturbance associated with implementation of the Optimal Recovery Alternative is 

indicated in Table 2.8-1. The disturbance indicated in Table 2.8-1 is new disturbance that would occur in 

addition to that from the No Action Alternative. 

Table 2.8-1 Optimal Recovery Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility 

Surface 

Disturbance 

(acres) 

Roads 

Access Roads1 1,627 miles 45 feet 8,875 

Well Pads 

New Single Well Pads 12,812 each 2.5 acres 32,030 

Twinned Well Pads (Additional Disturbance) 634 each 0.2 acre 127 

Multi-well Pads (Additional Disturbance) 0 each 0.2 acre 0 

Well Pad Subtotal 13,446 each 32,157 

Construction/Production Facilities 

Mancamps 2 each 5 acres 10 

Compressor Stations 5 each 20 acres 100 

Water Tank Batteries 5 each 3 acres 15 

Water Injection Facilities (Additional Disturbance) 25 each 0.2 acre 5 

Facilities Subtotal 130 

Linear Facilities 

Gas Gathering Pipelines – Common ROW 1,546 miles 0 feet 0 

Gas Gathering Pipelines – Cross-country 81 miles 20 feet 197 

DEIS 2-29 July 2010 
 

 

 

 

 

 

 

 

 

 

 

 

 

Table 2.8-1 Optimal Recovery Alternative Summary of New Surface Disturbance 

New Facilities 

Multiplier 

(number or 

miles) 

Size 

(ROW width [feet] 

or acres/facility 

Surface 

Disturbance 

(acres) 

Gas Transport Pipelines (Buried) 70 miles 75 feet 636 

Water Gathering Pipelines – Common ROW (Surface) 1,256 miles 0 feet 0 

Water Connecting Pipelines (Buried) 50 miles 75 feet 455 

Electric Power Lines 14 miles 100 feet 170 

Linear Facilities Subtotal 1,458 

Optimal Recovery Alternative New Disturbance 42,620 

GNBPA New Disturbance (%) 26% 

No Action Alternative New Disturbance (acre) 4,702 

Existing Surface Disturbance (acre) 7,766 

Total Surface Disturbance (acre) 55,088 

Total GNBPA Disturbed (%) 34% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable New Surface Disturbance (acre) 13,189 

Reclaimable No Action New Surface Dist (acre) 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 18,209 

Reclaimable Surface Disturbance (%) 33% 

Reclaimable Surface Disturbance as % of GNBPA 11.2% 

1

 Assume access road length of 0.127 mile/well pad. 

2

 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear 

Facilities summarized in the table above. 

2.8.1 Field Development Plan and Schedule 

The Optimal Recovery Alternative is designed to maximize recovery of the gas resource by increasing the 

number of wellbores to achieve 10-acre surface and downhole spacing throughout the GNBPA. 

Figure 2.8-1 illustrates the available locations for new wells. Based on proposed activities identified as 

common to all alternatives, KMG and other operators would drill an estimated 13,446 new wellbores in 

addition to the existing producing wells and approved/permitted wells yet to be drilled in the GNBPA. KMG’s 

activities would remain largely as outlined under the Proposed Action Alternative. Additional wells would be 

drilled at an average rate of approximately 672 wells per year using 28 drilling rigs and would be drilled over 

a period of approximately 20 years or until the resource base is fully developed. The total number of wells 

drilled during the life of the project or during any particular year would depend largely on factors outside of 

KMG’s control. The estimated productive life of each well would be approximately 30 to 50 years, and 

3 percent of the drilled wellbores might be dry principally due to mechanical failure. 

The drilling schedule, well drilling and completion parameters, equipment and manpower requirements, 

compressor stations, water disposal facilities, buried water and gas pipelines, electric power facilities, and 

ancillary facilities would be similar to that discussed under the Proposed Action Alternative. However, in 

some cases more facilities would be constructed because of the higher number of wells and increased gas 

volumes produced. 

DEIS 2-30 July 2010 
31 

32 

5 

6 

32 

11 

7 8 

31 32 

River 

Willow 

Creek 

Duch esne River 

21 23 24 19 20 21 23 24 19 20 21 22 23 21 22 24 19 20 22 22 28 23 

28 29 28 27 26 

30 29 

25 30 27 25 28 27 26 25 30 29 28 27 26 26 30 29 8-T4-R3
 28 27 26 4-T8-R22 25 30 29 4-T8-R21
 4-T8-R24 4-T8-R23 33 

0 4-T8-R20 Uintah 33 35 34 34 35 36 31 32 Area County 31 32 33 35 36 31 32 33 34 35 36 34 of 33 36 31 32 35 33 34 Detail Utah

Gree

8-T5-R3 n 0

5 5 4 3 2 2 1 6 3 6 5 4 3 2 1 6 5 4 3 2 1 5 4 7 6 2 1 8 4 3 

6 5 

7 8 9 10 10 11 12 11 12 7 8 9 

11 7 8 9 10 8 9 10 12 7 9 11 12 10 

17 16 15 14 13 18 17 4-T9-R21 16 15 14 13 18 17 4-T9-R22 16 15

14 13 18 17 4-T9-R23 15 

16 

14 13 18 17 16 15 14 Existing and Approved Wells 

Named Streams and Rivers 

Township/Range 

18 

19 20 21 

4-T9-R20 

22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 

4-T9-R24 

20 21 22 23 

Sections 

EIS Project Area 

Potential Locations for New Well Pads 

Optimal Recovery (1 pad per 10 acres) 

26 0 

30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 1 

35 

31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 35 36 31 32 33 34 

6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 12 7 8 9 10 11 

18 17 16 15 14 13 18 17 16 15 14 13 18 17 16 15 14 13 18 17 16 15 14 13 18 

4-T10-R24 

17 16 15 14 

19 20 21 

4-T10-R20 

22 23 24 19 20 

4-T10-R21 

21 22 23 24 19 20 

4-T10-R22 

21 22 23 24 19 20 

4-T10-R23 

21 22 23 24 19 20 21 22 

30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 

33 34 31 32 32 33 34 35 36 

35 36 31 31 32 33 34 36 36 31 32 34 35 33 33 34 35 

5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 1 6 5 4 3 2 

1012 0.5 

Scale in Miles 

2 0 1.5 1 0.5 2 

8 

17 

9 

16 

4-T11-R20 

11 10 

15 14

12 

13 

7 

18 

8 

17 4-T11-R21 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 

9 

16 

4-T11-R22 

11 10 

15 14

12 

13 

7 

18 

8 

17 

4-T11-R23 

9 10

16 15

11 

14 

12 

13 

7 

18 

8 

17 4-T11-R24 

9 10

15 16 

11 

14 

Scale in Kilometers 

Greater Natural Buttes 

Area Gas Development 

Project EIS 

19 20 21 22 23 Figure 2.8-1 

20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 19 20 21 22 23 24 

Optimal Recovery 

29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 25 30 29 28 27 26 Alternative 

31 32 33 34 35 

2-31

Tuesday, February 10, 2009 7:32:09 AM 

X:\0Projects\12100_013_Kerr_McGee_Greater_Natural_Buttes\Figures_Folder\PDEIS\Fig2_8-1_OptimalRecoveryAlternative.mxd 
 

 

 

 

2.8.2 Alternative-specific Activities 

2.8.2.1 Access Roads 

Approximately 1,627 miles of new access road would be constructed to 12,812 new well pads. Because 

many more well pads would be constructed than under the Proposed Action Alternative, average access 

road length would be shorter because of the greater well pad density. For this alternative, the estimated 

average new access road length would be 0.127 mile. 

2.8.2.2 Infill Drilling of Vertical Wells 

For onshore reservoirs, drilling individual vertical wells typically is the most technically and cost efficient 

method of recovering the gas resource. The location of the well pads would reflect avoidance of the 

following constraining factors: 

•	 Topography, including steep slopes that preclude construction of a well pad for a vertically drilled 

well; 

•	 The viewshed (line-of-sight from the centerline up to 0.5 mile along both sides of the river) of the 

White River corridor, outside of the Indian Trust Lands; and 

•	 Areas within 600 feet of the White River within the Indian Trust Lands. 

It has been estimated that approximately 470 locations at 10-acre spacing could not be drilled from vertical 

well pads in these constrained areas. Recovery of the natural gas resource would require the use of 

directional drilling techniques, which KMG has not yet determined to be technically or economically feasible 

within the GNBPA. Accordingly, these locations have not been analyzed in this EIS. 

All of the rest of the undrilled GNBPA would be assumed to be drilled using vertical wells from individual well 

pads. Accounting for 1,562 existing productive wells and 1,102 additional approved wells drilled under the 

No Action Alternative, there would be room for 12,812 new well pads drilled on 10-acre surface spacing. 

Approximately 27,699 acre-feet of water would be required to drill and complete the 13,446 total wells, or 

approximately 1,385 acre-feet annually during the 20 years required to complete this Optimal Recovery 

Alternative. 

The number of mancamps needed for the Optimal Recovery Alternative would be the same as that needed 

for all other action alternatives; two camps at 5 acres each. 

2.8.2.3 Gas Pipelines 

A total of approximately 1,627 miles of natural gas surface gathering pipeline would be installed to transport 

natural gas from project wells to larger buried pipelines that connect to processing facilities. Approximately 

1,546 miles (95 percent) would be placed in available access road ROWs, and approximately 81 miles 

(5 percent) would require cross-country routing outside of access road ROWs. Cross-country routing would 

require a 20-foot ROW for construction. Approximately 70 miles of larger-diameter, buried transport pipeline 

would be constructed within a 75-foot-wide construction ROW that would overlap with other ROWs when 

possible. 

2.8.2.4 Gas Compression and Processing 

Five compression sites would be constructed to meet project compression needs within the GNBPA; each 

site would require approximately 20 acres for the life of the facility. These facilities would provide a total 

additional 197,500 hp of compression; half gas-fired and half electrically driven. 

DEIS	 2-32 July 2010 
 

2.8.2.5 Electrical Power Requirements 

Under the Optimal Recovery Alternative, approximately 14.0 miles of overhead electric lines would be 

installed to provide power to the pumps at the proposed water disposal wellsites. The new power lines 

would be 35-kV distribution lines that would originate from the existing power grid. Pole mount transformers 

would be installed within 500 feet of each point of use to obtain 480-volt power for the pumps. The power 

lines would be installed within a 100-foot ROW. Surface disturbance associated with electric power line 

installation within the ROW would be reclaimed as soon as construction is completed. 

2.8.2.6 Water Disposal Facilities 

Under this alternative, 25 new disposal wells would be drilled in the GNBPA on existing well pads or using 

existing well borings located in Sections 19 through 36, T9S, R21E. Locations would be chosen based on 

suitable subsurface rock properties and water quality data. Sites of five of the more centrally located existing 

or proposed produced water disposal wells would contain several produced water storage tanks. 

Approximately 50 miles of 4- to 12-inch, buried polypropolene pipe water flowlines would be installed within 

a 75-foot-wide ROW to interconnect all new and existing water management facilities including salt water 

disposal wells, evaporation/recycle ponds, and centralized tank batteries. 

Transport of produced water would be handled in the same manner as discussed under the Proposed 

Action Alternative. For this alternative, annual truck transport of produced water is estimated to be 

approximately 393,114 truckloads over an average of approximately 10 miles roundtrip, assuming an 

average truck capacity of 100 bbls. 

In the event that KMG were to proceed with construction of a surface water gathering pipeline system 

co-located within access road ROW disturbance, similar to that described for the Proposed Action, 

approximately 1,256 miles of surface pipeline would be constructed. 

2.9 Alternatives Considered but Eliminated from Further Consideration 

The BLM considered two alternatives to the proposed project that were not carried forward for detailed 

analysis in subsequent chapters of this document. The following sections describe these alternatives and 

provide the rationale for why the BLM eliminated the alternatives from further detailed consideration. 

No Further Development: The BLM considered an alternative under which no further development would 

take place in the GNBPA. This alternative was eliminated from detailed analysis because ongoing oil and 

gas development continues on valid leases within the GNBPA as disclosed under existing NEPA decision 

documents (see Section 2.4.1). The decisions in the existing NEPA documents are not being revisited under 

this EIS. The no further development alternative is frequently mistaken for the No Action Alternative, which 

is required to be analyzed under NEPA. For this project, the No Action Alternative would occur if the BLM 

were to deny KMG’s proposal, and development would continue in the GNBPA under existing NEPA 

disclosures. The No Action Alternative is fully analyzed in this document (Section 2.4 and analysis sections 

in Chapter 4). 

Phased Development: The BLM considered a phased development alternative, which was intended to 

rotate concentrated disturbance activities through smaller, pre-defined areas (subareas), while the 

remainder of the GNBPA would be less impacted than under the Proposed Action. Under this alternative, oil 

and gas development activities would be restricted to one of several subareas within the GNBPA boundary. 

One subarea at a time would be open to oil and gas construction and development activities for a limited 

time period, after which construction and development activities would cease. An indicator, such as 

successful interim reclamation within a subarea, would be required to be met prior to developing a new 

subarea. Oil and gas extraction and processing would continue (i.e., operational activities) in the subarea, 

while construction and development activities would move to another subarea. An additional intent was to 

encourage concurrent and efficient reclamation of surface disturbance. 

DEIS 2-33 July 2010 
 

For the following reasons, the BLM eliminated this alternative from further detailed analysis in this EIS: 

•	 Phased development could not be imposed by the BLM on state, Tribal, and private lands within the 

GNBPA. These lands make up almost one-half (45 percent) of the GNBPA, thereby reducing the 

benefit of a phased development approach. 

•	 The BLM would still be required to process “reasonable access” ROW applications for development 

of private and state leases within the subareas not currently being developed (BLM Manual, Part 

2800.06 “Policy” [D], allowing owners of non-federal lands surrounded by public lands managed 

under the FLPMA to develop for the reasonable use and enjoyment of these non-federal lands). 

•	 Phased development could delay benefits to surface owners within the GNBPA (e.g., payments to 

the Ute Tribe for surface disturbance activities). In addition, job preference for Ute Tribe members 

when work activity occurs on Tribal lands could be delayed. 

•	 The GNBPA is primarily located within an already developed field. The Proposed Action would 

downspace existing development. Phased development would concentrate traffic and drilling 

activities in the active subarea, but production and maintenance activities in the existing field would 

continue regardless of subarea. 

•	 Under a phased development scenario operators would be unable to return to subareas where 

construction and development activity has ceased. This would prevent redevelopment of a subarea 

in the event that a change in commodity price or an improvement in drilling technology were to 

make the subsurface resource that was previously passed over economically viable. 

•	 Concentrated development under a phase development alternative would focus surface disturbance 

impacts within individual grazing allotments. This could result in rapid reduction in forage and a 

corresponding reduction in animal unit months (AUMs). 

2.10 Comparison of Alternatives 

A comparison of disturbance within the GNBPA associated with the four alternatives is provided in 

Table 2.10-1. Impacts by resource associated with the alternatives are provided in Table 2.10-2. 

DEIS	 2-34 July 2010 
Table 2.10-1 Disturbance Comparison for GNBPA Alternatives (Excluding Existing Condition) 

New Facilities 

Size 

(ROW width 

[feet] or 

acres/facility) 

New Surface Disturbance by Alternative 

No Action Proposed Action Resource Protection 

Multiplier 

(number or 

miles) 

Disturbance 

(acres or % 

of GNBPA) 

Multiplier 

(number or 

miles) 

Disturbance 

(acres or % 

of GNBPA) 

Multiplier 

(number or 

miles) 

Disturban

(acres or 

of GNBPA

Roads 

Access Roads1 45 feet 276 miles 1,503 760 miles 4,147 594 miles 3,238 

Well Pads 

New Single Well Pads 2.5 acres 1,102 each 2,755 3,041 each 7,603 1,484 each 3,710 

Twinned Well Pads (Additional Disturbance) 0.2 acre 0 each 0 634 each 127 634 each 127 Multi-well Pads (Additional Disturbance) 0.2 acre 0 each 0 0 each 0 1,557 each 311 

Well Pad Subtotal 1,102 each 2,755 3,675 each 7,729 3,675 each 4,148 

Construction/Production Facilities 

Mancamps 5 acres 0 each 0 2 each 10 2 each 10 Compressor Stations 20 acres 6 each 120 2 each 40 2 each 40 

Water Tank Batteries 3 acres 8 each 24 2 each 6 2 each 6 Water Injection Facilities (Additional Disturbance) 0.2 acre 0 each 0.0 15 each 3 15 each 3 

Construction/Production Facilities Subtotal 144 59 59 

Linear Facilities 

Gas Gathering Pipelines – Common ROW 0 feet 262 miles 0 722 miles 0 564 miles 0 Gas Gathering Pipelines – Cross-country 20 feet 14 miles 33 38 miles 92 30 miles 72 

Gas Transport Pipelines (Buried) 75 feet 0 miles 0 35 miles 318 35 miles 318 Water Gathering Pipelines – Common ROW (Surface) 0 feet 0 miles 0 587 miles 0 458 miles 0 

Water Connecting Pipelines (Buried) 75 feet 26 miles 236 25 miles 227 25 miles 227 Electric Power Lines 100 feet 2.5 miles 30 7 miles 85 7 miles 85 

Linear Facilities Subtotal 300 722 702 

New Surface Disturbance (acre) 4,702 12,658 8,147 

GNBPA New Disturbance (%) 2.9% 7.8% 5.0% 

No Action Alternative New Disturbance (acre) 4,702 4,702 

Existing Surface Disturbance (acre) 7,766 7,766 7,766 

Total Surface Disturbance (acre) 12,468 25,125 20,615 

Total GNBPA Disturbed (%) 7.7% 15.4% 12.7% 

Surface Disturbance Interim Reclamation Estimates2 

Reclaimable New Surface Disturbance (acre) 1,753 4,731 3,387 

Reclaimable No Action New Surface Dist (acre) 1,753 1,753 

Reclaimable Existing Surface Disturbance (acre) 3,267 3,267 3,267 

Total Est. Reclaimable Surface Disturbance (acre) 5,020 9,751 8,407 

Reclaimable Surface Disturbance (%) 40.3% 39% 41% 

Reclaimable Surface Dist as % of GNBPA 3.1% 6.0% 5.2% 

1 Assume access road length of 0.25 mile/well pad for No Action and Proposed Action; 0.4 mile/well pad for Resource Protection Alternative; 0.127 mile/well pad for Optimal Recove2 Interim reclamation estimates are based on the potential to reclaim 0.5 acre per new well pad, 27 feet ROW for new access roads, and all new Linear Facilities summarized in the tDEIS 2-35
 
Table 2.10-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Air Quality 

Air Quality (exceed National Ambient Air Quality Standards [NAAQS]) 

No No No Potential1 Sect

Acid Deposition (exceed U.S. Forest Service [USFS] threshold) Yes (1 area)2 Yes (1 area)2 Yes (1 area)2 Yes (1 area)2 SectVisibility (Class I) Cumulative Incremental impacts Incremental impacts Incremental impacts Sect

impacts > 1.0 < 1.0 dv < 1.0 dv < 1.0 dv 

deciview (dv) 

Visibility (Class II) Cumulative Incremental impacts Incremental impacts > Incremental impacts Sect

impacts > 1.0 dv > 1.0 dv at 2 areas 1.0 dv at 2 areas > 1.0 dv at 2 areas 

Greenhouse Gas (GHG) Emissions (103 tonne carbon dioxide 

equivalents [CO2e]/year) 

1,761 2,754 2,754 5,485 Sect

Cultural Resources and Native American Traditional Values 

Sites potentially encountered (incremental due to new surface disturbance) 

52 142 90 475 Sect

Geology 

Recoverable Gas Resources Over the Life of the wells (trillion 1.41 6.07 6.07 15.44 Sect

cubic feet [Tcf]) Recoverable Condensate Resources Over the Life of the Wells 22.3 86.5 86.5 118 Sect(million bbls) 

Land Use 

White River Special Recreation Management Area (SRMA) (incremental acres disturbed) 

7.8 49 32 164 Sect

Paleontology 

Potential Fossil Yield Classification (PFYC) Class 4 or 5 areas 4,467 12,025 7,740 40,489 Sect

(potential incremental acres disturbed) 

Range Resources 

AUMs Lost – BLM 352 947 609 3,186 TabAUMs Lost – BIA 26 71 46 239 Tab

Total AUMs Lost 378 1,018 655 3,425 

Number Rangeland Improvements Impacted (BLM land only) NA 26 15 27 Tab

Socioeconomics 

Energy Resource Recovery Sect

Natural Gas (Tcf) 1.41 6.07 6.07 15.44 Oil Condensates (million bbl) 22.3 86.5 86.5 117.9 

Projected end of production (year) 2051 2059 2059 2066 

Employment (number jobs) Sect

and 

Peak – development 1,790 4,302 4,302 9,024 

Average – production 239 875 875 1,712 

DEIS 2-36
 
Table 2.10-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Population – Duchesne and Uintah counties Sect

and 

Peak – development 2,585 5,590 5,590 8,368 Average – production 450 1,508 1,508 2,732 

Temporary and permanent housing demand in Duchesne and 1,593 3,447 3,447 5,159 Sect

Uintah counties during development (units) and 

Grazing – Reduction in annual cash farm receipts ($24 per As much as As much as As much as As much as Sect

AUM lost) $7,632 lost $24,432 lost $15,720 lost $82,200 lost Public Sector Revenues – Cumulative Life of Field3 (millions of 

2006 dollars) 

Sectand 

Ad Valorem Taxes 89.2 343.8 343.8 856.1 Utah Severance Taxes 270.5 1,146.7 1,146.7 2,709.5 Federal and Tribal Mineral Royalties 417.9 2,692.4 2,692.4 6,333.9 State Public School Fund Royalties 158.9 673.1 673.1 1,582.5 

Combined Public Sector Revenues 1,154.3 4,856.0 4,856.0 11,481.0 

Percent Increase over No Action N/A 321 321 895 

Soils 

High Constraint (incremental acres disturbed) 4,396 11,835 7,618 39,849 Tab

Moderate Constraint (incremental acres disturbed) 141 380 244 1,279 Low Constraint (incremental acres disturbed) 165 443 285 1,492 

Transportation and Access 

New Access Roads (miles) 276 760 594 1,627 Sect

Increase in Traffic Volume at Full Production (total number 0 20,948 20,948 59,162 Sect

vehicle miles) Number of Annual Incidents (mostly minor accidents and spills) 22 58 58 201 Sect

Vegetation 

Uinta Basin hookless cactus potential preferred habitat 1,576 4,369 2,731 14,201 Sect

(estimated incremental acres disturbed) 

Vegetation Type (estimated incremental acres disturbed) Tab

Salt-desert shrubland 1,932 5,279 3,437 17,775 Sagebrush shrubland 1,663 4,548 2,961 15,313 

Grassland 455 1,246 811 4,194 

Cliff/Canyon 217 593 386 1,997 

Riparian 143 189 29 637 Pinyon-juniper woodland 82 225 147 758 

Agriculture 30 81 53 274 Barren 178 490 319 1,650 Developed 2 7 4 22 

DEIS 2-37
 
Table 2.10-2 Impact Comparison by Resource for All Alternatives 

No Action Proposed Action Resource Protection Optimal Recovery 

Resource Alternative Alternative Alternative Alternative 

Visual Resources 

Visual Resource Management (VRM) Class II areas on federal lands (incremental acres disturbed) 

0 91 58 305 Sect

Incremental Disturbance Visible from (acres): Sect

Boaters on the White River 1,287 3,461 2,218 11,536 

Goblin City Overlook 140 377 242 1,257 

Water Resources 

Surface Water Uses (acre-feet/year) 550 800 800 1,925 Sect

100-year Floodplains (incremental acres disturbed) 325 288 0 1,510 Sect

Wilderness Characteristics 

BLM White River Natural Area (incremental acres disturbed) 0 0 0 0 Sect

Non-wilderness Study Area Lands with Wilderness 81 217 139 724 Sect

Characteristics (estimated incremental acres disturbed) 

Wildlife Resources 

Big Game Habitat (estimated incremental acres disturbed) Tab

4.15

Pronghorn Year-long Crucial 3,183 10,264 6,607 34,562 Pronghorn Year-long Substantial 67 179 116 604 Mule Deer Year-long Crucial 553 1,488 958 5,011 

Mule Deer Winter Substantial 68 183 118 615 Elk Winter Substantial 9 24 16 82 Rocky Mountain Bighorn Sheep Year-long Crucial 781 2,103 1,354 7,082 Bison Year-long Crucial Range 3,406 9,168 5,901 30,869 

Potential White-tailed Prairie Dog Habitat (estimated 4,258 11,644 7,581 39,206 Sectincremental acres disturbed) Greater Sage-grouse Habitat (estimated incremental acres Tab

disturbed) 4.15

2.0 Mile Lek Buffer 442 1,190 766 4,007 

Nesting 675 1,817 1,169 6,117 Brooding 1,782 4,797 3,088 16,153 Winter 1,356 3,649 2,349 12,288 

Fisheries Resources 

Estimated total water depletions for life of the project (acre/feet) 2,270 7,571 7,571 27,700 Sect

1 2006 meteorological data show modeled concentrations of ozone between 76 and 79 ppb; 2005 meteorological data show modeled concentrations of ozone below 76 ppb.
 2 Modeled deposition from action alternatives does not exceed Federal Land Managers’ Air Quality Related Values Workgroup (FLAG) thresholds, except for Mesa Verde National Park, w

thresholds for the No Action Alternative.
 

3 The public sector revenue projections assume constant natural gas prices of $4.59/thousand cubic feet (Mcf) and $45/barrel for liquids. However, energy prices fluctuate over time. Actua

or lower than shown, depending on future prices and production. Such variance would affect all alternatives.
 

DEIS 2-38