16128 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

DEPARTMENT OF THE INTERIOR 

Bureau of Land Management 

43 CFR Part 3160 

[LLWO300000 L13100000.PP0000 14X] 

RIN 1004–AE26 

Oil and Gas; Hydraulic Fracturing on 

Federal and Indian Lands 

AGENCY: Bureau of Land Management, 

Interior. 

ACTION: Final rule. 

SUMMARY: On May 11, 2012, the Bureau 

of Land Management (BLM) published 

in the Federal Register a proposed rule 

titled Oil and Gas; Well Stimulation, 

Including Hydraulic Fracturing, on 

Federal and Indian Lands. Because of 

significant public interest in hydraulic 

fracturing and this rulemaking, on May 

24, 2013, the BLM published in the 

Federal Register a supplemental notice 

of proposed rulemaking and request for 

comment titled Oil and Gas Hydraulic 

Fracturing on Federal and Indian Lands. 

The BLM has used the comments on the 

supplemental proposed rule and the 

earlier proposed rule in drafting this 

final rule. Key changes to the final rule 

include the allowable use of an 

expanded set of cement evaluation tools 

to help ensure that usable water zones 

have been isolated and protected from 

contamination, replacement of the ‘‘type 

well’’ concept to demonstrate well 

integrity with a requirement to 

demonstrate well integrity for all wells, 

more stringent requirements related to 

claims of trade secrets exempt from 

disclosure, more protective 

requirements to ensure that fluids 

recovered during hydraulic fracturing 

operations are contained, additional 

disclosure and public availability of 

information about each hydraulic 

fracturing operation, and revised 

records retention requirements to ensure 

that records of chemicals used in 

hydraulic fracturing operations are 

retained for the life of the well. The 

final rule also provides opportunities for 

the BLM to coordinate standards and 

processes with individual states and 

tribes to reduce administrative costs and 

to improve efficiency. 

DATES: This final rule is effective on 

June 24, 2015. 

ADDRESSES: 

Mail: U.S. Department of the Interior, 

Director (630), Bureau of Land 

Management, Mail Stop 2134 LM, 1849 

C St. NW., Washington, DC 20240, 

Attention: 1004–AE26. 

Personal or messenger delivery: 

Bureau of Land Management, 20 M 

Street SE., Room 2134 LM, Attention: 

Regulatory Affairs, Washington, DC 

20003. 

FOR FURTHER INFORMATION CONTACT: 

Steven Wells, Division Chief, Fluid 

Minerals Division, 202–912–7143 for 

information regarding the substance of 

the rule or information about the BLM’s 

Fluid Minerals Program. Persons who 

use a telecommunications device for the 

deaf (TDD) may call the Federal 

Information Relay Service (FIRS) at 1– 

800–877–8339 to contact the above 

individual during normal business 

hours. FIRS is available 24 hours a day, 

7 days a week to leave a message or 

question with the above individual. You 

will receive a reply during normal 

business hours. 

SUPPLEMENTARY INFORMATION: 

Executive Summary 

The BLM final rule on hydraulic 

fracturing serves as a much-needed 

complement to existing regulations 

designed to ensure the environmentally 

responsible development of oil and gas 

resources on Federal and Indian lands, 

which were finalized nearly thirty years 

ago, in light of the increasing use and 

complexity of hydraulic fracturing 

coupled with advanced horizontal 

drilling technology. This technology has 

opened large portions of the country to 

oil and gas development. 

The BLM began work on this rule in 

November 2010, when it held its first 

public forum amid growing public 

concern about the rapid expansion of 

complex hydraulic fracturing. Since that 

time, the BLM has published two 

proposed rules and held numerous 

meetings with the public and state 

officials, as well as many tribal 

consultations and meetings. The public 

comment period was open for more than 

210 days. During this period, the BLM 

received comments from more than 1.5 

million individuals and groups. The 

BLM reviewed and analyzed these 

comments based on thoughtful analysis 

and robust dialogue, which resulted in 

a rule that is more protective than the 

previous proposed rules and current 

regulations. It also strengthens oversight 

and provides the public with more 

information than is currently available, 

while recognizing state and tribal 

authorities and not imposing undue 

delays, costs, and procedures on 

operators. The final rule fulfills the 

goals of the initial proposed rules: To 

ensure that wells are properly 

constructed to protect water supplies, to 

make certain that the fluids that flow 

back to the surface as a result of 

hydraulic fracturing operations are 

managed in an environmentally 

responsible way, and to provide public 

disclosure of the chemicals used in 

hydraulic fracturing fluids. 

The final rule also: (1) Improves 

public awareness of where hydraulic 

fracturing has occurred and the 

existence of other wells or geologic 

faults or fractures in the area, as well as 

communicates what chemicals have 

been used in the fracturing process; (2) 

Clarifies and strengthens existing rules 

related to well construction to ensure 

integrity and address developments in 

technology; (3) Aligns requirements 

with state and tribal authorities with 

regard to water zones that require 

protection; and (4) Provides 

opportunities to coordinate standards 

and processes with individual states 

and tribes to reduce costs, increase 

efficiencies, and promote the 

development of more stringent 

standards by state and tribal 

governments. 

Various types of hydraulic fracturing 

have long been used on a relatively 

small scale to complete or to recomplete conventional oil and gas 

wells. More recently, hydraulic 

fracturing has been coupled with 

relatively new horizontal drilling 

technology in larger-scale operations 

that have allowed greatly increased 

access to shale oil and gas resources 

across the country, sometimes in areas 

that have not previously or recently 

experienced significant oil and gas 

development. These newer wells can, 

among other complexities, be 

significantly deeper and cover a larger 

horizontal area than the operations of 

the past. This increased complexity 

requires additional regulatory effort and 

oversight. 

Rapid expansion of this practice and 

its complexity have caused public 

concern about whether fracturing can 

lead to or cause the contamination of 

underground water sources, whether the 

chemicals used in fracturing pose risks 

to human health, and whether there is 

adequate management of well integrity 

and the fluids that return to the surface 

during and after fracturing operations. 

The BLM’s regulations that address 

issues surrounding hydraulic fracturing 

are at least 25–30 years old, and predate the current common use of the 

practice. In 2011, the Natural Gas 

Subcommittee of the Secretary of 

Energy’s Advisory Board recommended 

that the BLM undertake a rulemaking to 

ensure well integrity, water protection, 

and adequate public disclosure. Prior to 

that, in 2009 the American Petroleum 

Institute published a guidance 

document titled ‘‘Hydraulic Fracturing 

Operations-Well Construction and 

Integrity Guidelines, First Edition, 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16129 

October 2009,’’ commonly known as 

HF1, to provide guidance and highlight 

industry recommended practices for 

well construction and integrity for those 

wells that will be hydraulically 

fractured. The purpose of the guidance 

was to ensure protection of shallow 

groundwater aquifers and the 

environment while enabling 

economically viable development of oil 

and natural gas resources. More 

recently, regulations from states, such as 

Colorado and Wyoming, and 

professional papers, such as King, 

George, SPE 152596, (Feb. 2012), 

focused on the estimation, analyses, and 

control of risks from hydraulic 

fracturing operations. All of these 

factors have led to, and informed, this 

rulemaking. To ensure that these 

standards adequately address emerging 

technological developments and health 

and environmental protections, the BLM 

will evaluate the adequacy of this 

rulemaking 7 years after the date of 

publication. 

Pursuant to the Federal Land Policy 

and Management Act (FLPMA), Indian 

mineral leasing laws, and other statutes, 

the BLM is charged with administering 

oil and gas operations in a manner that 

protects Federal and Indian lands while 

allowing for appropriate development of 

the resource. The BLM oversees 

approximately 700 million subsurface 

acres of Federal mineral estate and 

carries out some of the regulatory duties 

of the Secretary of the Interior for an 

additional 56 million acres of Indian 

mineral estate across the United States. 

Currently, nearly 36 million acres of 

Federal land are under lease for 

potential oil and gas development in 33 

states. As of June 30, 2014, there were 

approximately 47,000 active oil and gas 

leases on public lands, and 

approximately 95,000 oil and gas wells. 

Like other BLM regulations, this final 

rule applies to oil and gas operations on 

public lands (which include split estate 

lands, i.e., lands where the surface is 

owned by an entity other than the 

United States), as well as operations on 

Indian lands, to ensure that these lands 

and communities all receive the same 

level of protection as provided on 

public lands. 

Oil and gas leasing decisions on 

public lands are made through a 

thorough, deliberative, and transparent 

process rooted in Resource Management 

Plans (RMPs) that cover virtually all 

BLM-administered public land and 

related mineral estate. Oil and gas 

decisions contained within BLM RMPs 

also apply to lands where the surface is 

privately owned, but the mineral estate 

is in Federal ownership. The BLM 

establishes, amends, and revises RMPs 

as required by the FLPMA with 

involvement by the community and 

stakeholders. As part of the land use 

planning process, the BLM engages the 

public in a variety of ways and conducts 

environmental reviews as required by 

the National Environmental Policy Act 

(NEPA), and other applicable natural 

and cultural resource protection 

authorities. While the public makes 

known to the BLM which lands they are 

interested in leasing, prior to leasing 

any lands, the BLM undertakes the 

appropriate NEPA review and provides 

an opportunity for the public to review 

and comment on the analyses and 

documents that the agency prepares. 

Existing Requirements 

Relevant existing requirements for oil 

and gas operations are set out at 43 CFR 

3162.3–1 and Onshore Oil and Gas 

Orders 1, 2 and 7. Most of these 

requirements have been in place for at 

least 25 years. This final rule will 

supplement the existing requirements, 

which will remain in place. On either 

Federal leaseholds, or Indian lands, an 

operator may not begin operations until 

it has filed an Application for a Permit 

to Drill (APD) with the BLM and 

received approval from the BLM to 

commence operations. Existing Federal 

law requires the BLM to post notices of 

APDs for oil and gas development on 

public lands for public inspection for 30 

days, during which time the public may 

express any concerns to the BLM’s 

authorized officer as the agency 

conducts a site-specific environmental 

analysis of the proposed well site 

proposal. Those concerns and other 

issues identified earlier in the process, 

or during site examinations, may result 

in conditions of approval (COA) on the 

operator’s drilling permit that require, 

forbid, or control specified activities or 

disturbances. Examples of COAs 

include providing for road 

improvements and erosion control 

measures, or applying seasonal 

restrictions on some activities. In 

addition, baseline water testing is a best 

management practice that the BLM 

encourages. The BLM may require water 

testing and monitoring, particularly if 

water quality impacts are a significant 

concern based on local conditions, and 

where the BLM or a cooperating 

landowner or manager manages the 

surface estate where testing could yield 

useful water quality information. This is 

consistent with what several states, 

including California, Colorado, and 

Wyoming, are already doing. The BLM 

does not post for public inspection 

notices of APDs for Indian oil and gas 

leases or agreements because there is no 

requirement in the Indian leasing 

statutes similar to that in Section 17 of 

the Mineral Leasing Act. 

Under Onshore Oil and Gas Order 1, 

Approval of Operations, the location of 

the well must be identified and 

important aspects of the proposed 

operations described. Onshore Order 2 

requires all usable water zones to be 

protected by steel casing and cement, 

and requires the casing, once in place, 

to be pressure tested. Casing and cement 

must meet specific design criteria, 

which BLM engineers verify as part of 

the permit review process. When a well 

is no longer capable of producing, 

Onshore Order 2 mandates minimum 

standards for the placement, quality, 

and verification of cement plugs to 

ensure that any remaining oil and gas 

cannot migrate into usable water zones. 

BLM inspectors witness aspects of 

drilling and plugging operations to 

ensure that the operator is in 

compliance with Onshore Order 2 and 

the permit to drill. 

New Requirements 

With this rule, the BLM establishes 

new requirements to ensure wellbore 

integrity, protect water quality, and 

enhance public disclosure of chemicals 

and other details of hydraulic fracturing 

operations. The rule requires an 

operator planning to conduct hydraulic 

fracturing to do the following: 

• Submit detailed information about 

the proposed operation, including 

wellbore geology, the location of faults 

and fractures, the depths of all usable 

water, estimated volume of fluid to be 

used, and estimated direction and 

length of fractures, to the BLM with the 

APD or a Sundry Notice and Report on 

Wells (Form 3160–5) as a Notice of 

Intent (NOI) to hydraulically fracture an 

existing well; 

• Design and implement a casing and 

cementing program that follows best 

practices and meets performance 

standards to protect and isolate usable 

water, defined generally as those waters 

containing less than 10,000 parts per 

million of total dissolved solids (TDS); 

• Monitor cementing operations 

during well construction; 

• Take remedial action if there are 

indications of inadequate cementing, 

and demonstrate to the BLM that the 

remedial action was successful; 

• Perform a successful mechanical 

integrity test (MIT) prior to the 

hydraulic fracturing operation; 

• Monitor annulus pressure during a 

hydraulic fracturing operation; 

• Manage recovered fluids in rigid 

enclosed, covered or netted and 

screened above-ground storage tanks, 

with very limited exceptions that must 

be approved on a case-by-case basis; 

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16130 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

1Secretary of Energy’s Advisory Board 

recommendations can be downloaded from http:// 

energy.gov/seab/downloads/fracfocus-20-task-forcereport. 

2http://www.gwpc.org/major-improvementsfracfocus-announced. 

• Disclose the chemicals used to the 

BLM and the public, with limited 

exceptions for material demonstrated 

through affidavit to be trade secrets; 

• Provide documentation of all of the 

above actions to the BLM. 

Specifically, this final rule will add to 

existing requirements by providing 

information to the BLM and the public 

on the location, geology, water 

resources, location of other wells or 

fracture zones in the area, and fracturing 

plans for the operation before the well 

is permitted. To ensure well integrity, 

the final rule will require specified best 

practice performance standards for all 

wells, including cement return and 

pressure testing for surface casing, 

cement evaluation logs for intermediate 

and production casing, and remediation 

plans and cement evaluation logs for 

any surface casing that does not meet 

performance standards. 

The final rule eliminates the use of 

‘‘type wells’’ in demonstrating well 

integrity, and requires that specified 

best practices be used and demonstrated 

for all wells, not just a sample well. For 

surface casing, the final rule does not 

require a cement evaluation log (CEL) 

for each well, substituting other equally 

or more protective performance 

standards, including cement returns and 

pressure testing. For any surface casing 

not meeting these performance 

standards, an approved remedial plan 

and CEL will be required. For 

intermediate and production casing not 

cemented to the surface, a CEL will be 

required for all wells. 

The final rule will require interim 

storage of all produced water in rigid 

enclosed, covered, or netted and 

screened above-ground tanks, subject to 

very limited exceptions in which lined 

pits could be used. 

Public disclosure of all chemicals, 

subject to limited exceptions for trade 

secret material, will be required after 

fracturing operations are complete. The 

existing database, FracFocus (http://

fracfocus.org), can be used for this 

disclosure. 

FracFocus is managed by the Ground 

Water Protection Council (GWPC), a 

non-profit organization of state water 

quality regulatory agencies, and by the 

Interstate Oil and Gas Compact 

Commission (IOGCC), a multi-state 

government agency charged with 

balancing oil and gas development with 

environmental protection. The BLM will 

continue to work with FracFocus in 

coordination with the U.S. Department 

of Energy (DOE) to ensure that the 

recommendations of the Secretary of 

Energy’s Advisory Board for 

improvement of the database are made.1

Specifically, the BLM is in the process 

of finalizing a Memorandum of 

Understanding (MOU) with the GWPC 

to ensure, among other things, that the 

database can be searched and 

downloaded easily. In a press release 2

on February 26, 2015 GWPC and the 

IOGCC, joint venture partners in the 

FracFocus initiative, announced the 

release of improvements to FracFocus’ 

system functionality. The new features 

for 2015 include: 

• Reducing the number of human 

errors in disclosures 

• Expanding the public’s ability to 

search records 

• Providing public extraction of data 

in a ‘‘machine readable’’ format and 

• Updating educational information 

on chemical use, oil and gas production, 

and potential environmental impacts. 

As a part of the MOU with GWPC, 

FracFocus will automatically notify the 

BLM when an operator uploads 

chemical disclosure information about a 

Federal or Indian well. The BLM will 

obtain the information from FracFocus 

and keep those records in compliance 

with all pertinent record management 

requirements. 

The BLM developed this final rule 

with the intention of improving public 

awareness and strengthening oversight 

of hydraulic fracturing operations 

without introducing unnecessary new 

procedures or delays in the process of 

developing oil and gas resources on 

public and Indian lands. Some states, 

including Alaska, Arkansas, Colorado, 

Illinois, Michigan, New Mexico, Ohio, 

Oklahoma, Pennsylvania, Texas, Utah, 

and Wyoming have regulations in place 

addressing hydraulic fracturing 

operations. Operators with leases on 

Federal lands must comply with both 

the BLM’s regulations and with state 

operating requirements, including state 

permitting and notice requirements to 

the extent they do not conflict with 

BLM regulations. To address concerns 

from states and tribes about possible 

duplicative efforts, the final rule 

provides that in situations in which 

specific state or tribal regulations are 

demonstrated to be equal to or more 

protective than the BLM’s rules, the 

state or tribe may obtain a variance. 

Such a variance will allow for 

enforcement of the more protective state 

or tribal rule. 

For many years, the BLM has 

maintained a number of agreements 

with certain states and tribes concerning 

implementation of the various 

regulatory programs in logical and 

effective ways. The BLM will work with 

states and tribes to establish formal 

agreements that will capitalize on the 

strengths of partnerships, and reduce 

duplication of effort for agencies and 

operators, particularly by implementing 

the final rule as consistently as possible 

with state or tribal regulations. 

The provisions in this final rule 

provide for the BLM’s consistent 

oversight and establish a baseline for 

environmental protection across all 

public and Indian lands undergoing 

hydraulic fracturing. The BLM has 

analyzed the costs and the benefits of 

this proposed action in an 

accompanying Regulatory Impact 

Analysis available in the rulemaking 

docket. The BLM estimates that the rule 

will impact about 2,800 hydraulic 

fracturing operations per year, but that 

it could impact up to 3,800 operations 

per year based on previous levels of 

activity on Federal lands and growing 

activity on Indian lands. The BLM 

estimates that the compliance cost will 

be about $11,400 per well, or about $32 

million per year. On average this 

equates to approximately 0.13 to 0.21 

percent of the cost of drilling a well. 

Many of the requirements generally 

are consistent with industry guidance, 

the voluntary practice of operators, and 

some are required by state regulations. 

So to the extent that industry is already 

in compliance, the cost of several of the 

provisions may be overestimated. The 

improvements also provide significant 

benefits to all Americans by avoiding 

potential damages to water quality, the 

environment, and public health. The 

rule creates a consistent, predictable, 

regulatory framework, in accordance 

with the BLM’s stewardship 

responsibilities for hydraulic fracturing 

under the FLPMA and the Indian 

mineral leasing statutes. 

I. Background 

II. Discussion of the Final Rule and 

Comments on the Proposed Rules 

III. Procedural Matters 

I. Background 

Well stimulation techniques, such as 

hydraulic fracturing, are commonly 

used by oil and natural gas producers to 

increase the volumes of oil and natural 

gas that can be extracted from wells. 

Hydraulic fracturing techniques are 

particularly effective in enhancing oil 

and gas production from shale gas or oil 

formations. Until quite recently, shale 

formations rarely produced oil or gas in 

commercial quantities because shale 

does not generally allow the flow of 

hydrocarbons to wellbores unless 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16131 

physical changes to the properties of the 

rock can be induced. The development 

of horizontal drilling, combined with 

hydraulic fracturing, has made the 

production of oil and gas from shale 

feasible. Hydraulic fracturing involves 

the injection of fluid under high 

pressure to create or enlarge fractures in 

the reservoir rocks. The fluid that is 

used in hydraulic fracturing is usually 

accompanied by proppants, such as 

particles of sand, which are carried into 

the newly fractured rock and help keep 

the fractures open once the fracturing 

operation is completed. The proppantfilled fractures become conduits for 

fluid migration from the reservoir rock 

to the wellbore and the fluid is 

subsequently brought to the surface. In 

addition to the water and sand (which 

together typically make up 98 to 99 

percent of the materials pumped into a 

well during a fracturing operation), 

chemical additives are also frequently 

used. These chemicals can serve many 

functions in hydraulic fracturing, 

including limiting the growth of bacteria 

and preventing corrosion of the well 

casing. The exact formulation of the 

chemicals used varies depending on the 

rock formations, the well, and the 

requirements of the operator. 

Some simple types of hydraulic 

fracturing techniques have been used on 

a small scale in oil and gas production 

for decades. However, as discussed in 

different parts of the preamble, 

hydraulic fracturing operations in recent 

years have become more complex, 

involving the exploration of and 

production from significantly deeper 

formations and across much larger 

subsurface areas through the use of 

horizontal drilling techniques. 

The BLM estimates that about 90 

percent of the approximately 2,800 new 

wells spudded in 2013 on Federal and 

Indian lands were stimulated using 

hydraulic fracturing techniques. Over 

the past 10 years, there have been 

significant technological advances in 

horizontal drilling, which is now 

frequently combined with hydraulic 

fracturing. This combination, together 

with the discovery that these techniques 

can release significant quantities of oil 

and gas from large shale deposits, has 

led to production from geologic 

formations in parts of the country that 

previously did not produce significant 

amounts of oil or gas. The expansion of 

exploration and production across the 

United States has significantly increased 

public awareness of hydraulic fracturing 

and the potential impacts that it may 

have on water quality and water 

consumption, and increased calls for 

stronger regulation and safety protocols. 

The BLM’s engineers and field managers 

have decades of experience exercising 

oversight of these wells during the 

evolution of this technology. This 

expertise, together with input from the 

public, industry, state, academic and 

other experts discussed below, forms 

the basis for the decision that new rules 

are needed and for the requirements 

contained in this rule. 

The BLM’s existing hydraulic 

fracturing regulations are found at 43 

CFR 3162.3–2. Those regulations were 

established in 1982 and last revised in 

1988, long before the latest hydraulic 

fracturing technologies were developed 

or became widely used. The Department 

of the Interior (Department) held a 

forum on hydraulic fracturing on 

November 30, 2010, in Washington, DC, 

attended by the Secretary of the Interior 

and more than 130 interested parties. 

The BLM later hosted public forums (in 

Bismarck, North Dakota on April 20, 

2011; Little Rock, Arkansas on April 22, 

2011; and Golden, Colorado on April 25, 

2011) to collect broad input on the 

issues surrounding hydraulic fracturing. 

More than 600 members of the public 

attended the April 2011 forums. Some 

of the comments frequently heard 

during these forums included concerns 

about water quality, water consumption, 

and a desire for improved 

environmental safeguards for surface 

operations. Commenters also strongly 

encouraged the agency to require public 

disclosure of the chemicals used in 

hydraulic fracturing operations on 

Federal and Indian lands. Some 

commenters from the oil and gas 

industry suggested changes that would 

make the implementation of the rule 

more practicable from their perspective, 

while others opposed adoption of any 

such rules affecting hydraulic fracturing 

on the Federal mineral estate. 

Around the time of the BLM’s forums, 

at the direction of President Obama, the 

Secretary of Energy convened a Shale 

Gas Production Subcommittee 

(Subcommittee) of the Secretary of 

Energy Advisory Board to evaluate 

hydraulic fracturing issues. The 

Subcommittee met with industry, 

service providers, state and Federal 

regulators, academics, environmental 

groups, and many other stakeholders. 

On August 18, 2011, the Subcommittee 

issued initial recommendations in its 

‘‘90-day Interim Report.’’ The 

Subcommittee issued its final report, 

titled ‘‘Shale Gas Production 

Subcommittee Second Ninety Day 

Report’’ on November 18, 2011. The 

Subcommittee recommended, among 

other things, that more information be 

provided to the public about hydraulic 

fracturing operations, irrespective of 

whether those operations occur on the 

Federal mineral estate, including 

disclosure of the chemicals used in 

fracturing fluids. The Subcommittee 

also recommended the adoption of 

stricter standards for wellbore 

construction and testing. The final 

report also recommended that operators 

engaging in hydraulic fracturing 

undertake pressure testing to ensure the 

integrity of all casings, as well as the use 

of FracFocus as a means to report the 

use of hydraulic fracturing chemicals. 

These reports are available to the public 

from the Department of Energy’s Web 

site at http://www.shalegas.energy.gov. 

On May 11, 2012, the BLM published 

in the Federal Register the initial 

proposed rule titled ‘‘Oil and Gas; Well 

Stimulation, Including Hydraulic 

Fracturing, on Federal and Indian 

Lands’’ (77 FR 27691). The comment 

period on the initial proposed rule 

closed on July 10, 2012. At the request 

of public commenters, on June 26, 2012, 

the BLM published in the Federal 

Register a notice extending the 

comment period for 60 days (77 FR 

38024). The extended comment period 

closed on September 10, 2012. The BLM 

received over 177,000 comments on the 

initial proposed rule from individuals, 

Federal and state governments and 

agencies, interest groups, and industry 

representatives. 

After reviewing the comments on the 

proposed rule, the BLM published a 

supplemental notice of proposed 

rulemaking on May 24, 2013 (78 FR 

31636). The BLM received numerous 

requests for extension of the comment 

period on the supplemental proposed 

rule. Because of the complexity of the 

rule and well stimulation procedures, 

the BLM extended the comment period 

on the rule for 60 days. The closing date 

of the extended comment period was 

August 23, 2013. The BLM received 

over 1.35 million comments on the 

supplemental proposed rule. 

Substantive comments on the initial 

proposed and supplemental proposed 

rules that informed the BLM’s decisions 

on the final rule are discussed in the 

section-by-section discussion of this 

preamble. 

This final rule applies to all wells 

regulated by the BLM, whether on 

Federal, tribal, or individual Indian 

trust or restricted fee lands. The lands 

covered by the rule have not changed 

since the rule was first proposed. 

Tribal Consultation and Coordination 

With States 

Tribal consultation is a critical part of 

this rulemaking effort, and the 

Department is committed to making 

sure tribal leaders play a significant role 

as the BLM and the tribes work together 

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16132 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

to develop resources on public and 

Indian lands in a safe and responsible 

way. During the proposed rule stage, the 

BLM initiated government-togovernment consultation with tribes on 

the proposed rule and offered to hold 

follow-up consultation meetings with 

any tribe that desired to have an 

individual meeting. In January 2012, the 

BLM held four regional tribal 

consultation meetings, to which over 

175 tribal entities were invited. To build 

upon established local relationships, the 

individual follow-up consultation 

meetings involved the local BLM 

authorized officers and management, 

including BLM State Directors. The 

BLM distributed copies of a draft rule to 

affected federally recognized tribes in 

January 2012 and invited comments 

from affected tribes, which were also 

considered in developing this final rule. 

After the issuance of the proposed rule, 

tribal governments, tribal members, and 

individual Native American mineral 

owners were also invited to comment 

directly on the proposed rule. 

In June 2012, the BLM held additional 

regional consultation meetings in Salt 

Lake City, Utah; Farmington, New 

Mexico; Tulsa, Oklahoma; and Billings, 

Montana. Eighty-one tribal members 

representing 27 tribes attended the 

meetings. In these sessions, the BLM 

and tribal representatives engaged in 

substantive discussions of the proposed 

hydraulic fracturing rule. A variety of 

issues were discussed, including, but 

not limited to, the applicability of tribal 

laws, validating water sources, 

inspection and enforcement, wellbore 

integrity, and water management, 

among others. Additional individual 

consultations with tribal representatives 

have taken place since that time. Also, 

consultation meetings were held at the 

National Congress of American Indian 

Conference in Lincoln, Nebraska, on 

June 18, 2012, and at New Town, North 

Dakota on July 13, 2012. 

After publication of the supplemental 

proposed rule, the BLM again held 

regional meetings with tribes in 

Farmington, New Mexico, and 

Dickinson, North Dakota in June 2013. 

Representatives from six tribes attended. 

The discussions included a variety of 

tribal-specific and general issues. One 

change resulting from those discussions 

is the re-drafting of final section 3162.3– 

3(k) to clarify that tribal and state 

variances are separate from variances for 

a specific operator. The BLM again 

offered to follow up with one-on-one 

consultations, and several such 

meetings were held with individual 

tribes. Several tribes, tribal members, 

and associations of tribes provided 

comments on the supplemental 

proposed rule. The BLM understands 

the importance of tribal sovereignty and 

self-determination, and seeks to 

continuously improve its 

communications and government-togovernment relations with tribes. 

Responses from tribal representatives 

informed the agency’s actions in 

defining the scope of acceptable 

hydraulic fracturing operations. One of 

the outcomes of these meetings is the 

requirement in this rule that operators 

certify to the BLM that operations on 

Indian lands comply with applicable 

tribal laws. 

In March 2014, the BLM invited tribes 

to participate in another meeting in 

Denver, Colorado. Representatives from 

seven tribes attended. There was 

significant discussion of issues raised in 

the comments on the supplemental 

proposed rule. The BLM subsequently 

held several consultations with 

individual tribes. 

The BLM has been and will continue 

to be proactive about tribal consultation 

under the Department’s Tribal 

Consultation Policy, which emphasizes 

trust, respect, and shared responsibility 

in providing tribal governments an 

expanded role in informing Federal 

policy that impacts Indian lands. 

Several tribal representatives and 

tribal organizations commented that the 

hydraulic fracturing rule should not 

apply on Indian land, or that tribes 

should be allowed to decide not to have 

the rule apply on their land (that is, 

‘‘opt out’’ of the rule). However, the 

Indian Mineral Leasing Act (IMLA) 

provides in a pertinent part as follows: 

‘‘All operations under any oil, gas, or 

other mineral lease issued pursuant to 

the terms . . . of this title or any other 

Act affecting restricted Indian lands 

shall be subject to the rules and 

regulations promulgated by the 

Secretary of the Interior.’’ 25 U.S.C. 

396d. The Department has consistently 

applied uniform regulations governing 

mineral resource development on 

Indian and Federal lands. Thus, an ‘‘opt 

out’’ provision would not be consistent 

with the Department’s responsibilities 

under IMLA, and the final rule does not 

provide such an option. 

There has also been a suggestion that 

the Secretary should delegate her 

regulatory authority to the tribes if the 

tribe has regulations that meet or exceed 

the standards in the BLM regulation. 

The IMLA does not authorize the 

Secretary to delegate her regulatory 

responsibilities to the tribes, and 

therefore the final rule does not include 

a delegation provision. Nonetheless, 

there are opportunities for tribes to 

assert more control over oil and gas 

operations on tribal land by entering 

into Tribal Energy Resource Agreements 

under the Indian Energy Development 

and Self-Determination Act (part of the 

Energy Policy Act of 2005), and to 

pursue contracts under the Indian SelfDetermination and Education 

Assistance Act of 1975. 

Also, the final rule defers to state (on 

Federal land) or tribal (on Indian land) 

designations of aquifers as either 

requiring protection from oil and gas 

operations, or as exempt from the 

requirement to isolate water-bearing 

zones in section 3162.3–3(b), so long as 

those designations are not inconsistent 

with protections required pursuant to 

the SDWA (also see the definition of 

‘‘usable water’’). Revised section 

3162.3–3(k) provides that for lands 

within the jurisdiction of a state or a 

tribe, that state or tribe could work with 

the BLM to craft a variance that would 

allow compliance with state or tribal 

requirements to be accepted as 

compliance with the rule, for state or 

tribal provisions that are found to meet 

or exceed this rule’s standards. The 

BLM would enforce the variance as the 

Federal rule and the appropriate State or 

tribe would enforce the variance under 

its authority. 

The BLM will continue its 

coordination with states and tribes to 

establish or review and strengthen 

existing agreements related to oil and 

gas regulation and operations. During 

the rulemaking process, the BLM hosted 

multiple discussions with state 

governments to enhance coordination 

with oil and gas permitting, inspection, 

and enforcement. In August 2013, and 

then again in March 2014, the Acting 

Assistant Secretary for Land and 

Minerals Management invited the 

Governors and their representatives 

from those states with significant oil 

and gas operations, to meet with the 

BLM and discuss the objectives of the 

ongoing rulemaking as well as potential 

options for establishing agreements to 

assist in implementing the BLM’s oil 

and gas program. The BLM’s overall 

intent for these discussions is to 

minimize duplication and maximize 

flexibility though its coordination with 

states and tribes. We anticipate that 

these new and improved agreements 

will reduce regulatory burdens and 

increase efficiency, while fulfilling the 

Secretary’s responsibilities mandated by 

statutes as steward for the public lands 

and trustee for Indian lands. As this rule 

is implemented, the BLM will 

continuously review these agreements 

along with the new variance process 

allowed by the rule, and consider 

improvements as necessary. 

On Federal lands, the BLM enforces 

BLM regulations and lease conditions, 

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3See updated FracFocus link: http://

www.fracfocus.org/welcome. 

4Secretary of Energy’s Advisory Board 

recommendations (http://energy.gov/seab/

downloads/fracfocus-20-task-force-report) includes 

the areas of improvement. 

and the states enforce their oil and gas 

regulations. On Indian lands, the BLM 

enforces Federal regulations and the 

terms of the leases, and the tribes have 

the power to enforce their own law. 

Disclosure of Chemicals 

The BLM is working closely with the 

GWPC and the IOGCC, in coordination 

with the DOE, to provide for the 

disclosure of chemicals in the hydraulic 

fracturing fluids by the operators to the 

BLM through the existing public access 

Web site, www.fracfocus.org. As of June 

2013, the FracFocus database was 

upgraded to FracFocus 2.0. These 

upgrades were designed to enhance 

several aspects of the site’s 

functionality, such as its search and 

reports features and geographic 

information system mapping, for all 

users. As mentioned earlier, the GWPC 

and IOGCC, joint venture partners in the 

FracFocus initiative, announced the 

release of several improvements to 

FracFocus’ system functionality. The 

new features are designed to reduce the 

number of human errors in disclosures, 

expand the public’s ability to search 

records, provide public extraction of 

data in a ‘‘machine readable’’ format, 

and update educational information on 

chemical use, environmental impacts 

from oil and gas production, and 

potential environmental impacts. The 

new self-checking features in the system 

will help companies detect and correct 

possible errors before disclosures are 

submitted. This feature will detect 

errors verifying that Chemical Abstract 

Service (CAS) numbers meet the proper 

format. 

As of March 1, 2015, this online 

database includes information provided 

by operators concerning oil and gas 

wells in 20 states, and it is our 

understanding that a few more states are 

considering use of this database. It 

includes information from over 72,700 

wells and from more than 500 

companies. The list of states currently 

using FracFocus and the states 

considering using FracFocus are listed 

as follows: 3

States currently using 

FracFocus 

States proposing to 

use FracFocus 

1 Alabama .............. 1 Alaska. 

2 California ............. 2 Florida. 

3 Colorado .............. 3 Kentucky. 

4 Illinois ................... 4 Nevada. 

5 Kansas.

6 Louisiana.

7 Michigan.

8 Minnesota.

9 Mississippi.

States currently using 

FracFocus 

States proposing to 

use FracFocus 

10 Montana.

11 Nebraska.

12 North Dakota.

13 Ohio.

14 Oklahoma.

15 Pennsylvania.

16 South Dakota.

17 Tennessee.

18 Texas.

19 Utah.

20 West Virginia.

The Secretary of Energy Advisory 

Board’s Task Force on FracFocus 2.0 has 

identified a number of areas in which 

FracFocus needs improvement.4 The 

BLM is in continued discussion with 

the GWPC and expects further progress 

in ensuring that the site meets key 

elements addressed by the Task Force 

report. Specifically, the BLM expects 

improvement in the database to allow 

users to search by chemical, well, 

company, or geography; in quality 

control; and in the capacity to handle 

high volumes of information. 

The BLM recognizes the efforts of 

some states to regulate hydraulic 

fracturing and seeks to avoid 

duplicative regulatory requirements. It 

is important to recognize that a major 

impetus for a separate BLM rule is that 

states are not legally required to meet 

the stewardship standards that apply to 

public lands and do not have trust 

responsibilities for Indian lands under 

Federal laws. Thus, the rule may 

expand on or set different standards 

from those of states that regulate 

hydraulic fracturing operations. This 

final rule encourages efficiency in the 

collection of data and the reporting of 

information by allowing operators in 

states that require disclosure on 

FracFocus to meet both the state and the 

BLM requirements through a single 

submission to FracFocus. 

The BLM encourages the public 

disclosure of all chemicals used in any 

hydraulic fracturing operation. 

However, because the identities of some 

chemicals may be entitled to protection 

under Federal law as trade secrets, the 

BLM is allowing that information to be 

withheld if the operator and any other 

owner of the trade secret submit 

affidavits containing specific 

information explaining the reasons for 

the claim for protection. If the BLM has 

questions about the validity of the claim 

for protection, the BLM can require the 

operator to provide the withheld 

information to the bureau, and then 

would make a determination as to 

whether the data is properly withheld 

from the public. 

Existing Oil and Gas Development 

Process 

The BLM has an extensive process in 

place to ensure that operators conduct 

oil and gas operations in an 

environmentally sound manner that 

protects resources. This rule adds 

specific requirements for hydraulic 

fracturing operations, which 

supplement the existing requirements. 

The following is a description of these 

existing processes and requirements: 

Resource Management Plans. Section 

202 of the FLPMA requires the BLM to 

develop and maintain land use plans 

(the BLM refers to these plans as 

Resource Management Plans, or RMPs). 

The RMP serves as the basis for all land 

use decisions the BLM makes, including 

decisions to allow oil and gas leasing, 

allow oil and gas leasing under certain 

conditions, or prohibit oil and gas 

leasing altogether. The RMP applies to 

public lands, including the Federal 

mineral estate; however, it does not 

apply to Indian land or to surface estates 

managed by other Federal agencies such 

as the USDA Forest Service. The tribes 

and other Federal agencies rely on their 

own planning guidance when 

determining if their lands are suitable 

for oil and gas development. The 

FLPMA also requires that the public be 

given ample opportunity to participate 

in the development, maintenance, and 

revision of land use plans. Regulations 

implementing the FLPMA (43 CFR 

1610.2) require the BLM field offices to 

publish notices to prepare, amend, or 

revise RMPs in the Federal Register and 

local newspapers. In addition, the BLM 

must send notices to groups and 

individuals who have expressed an 

interest in being involved in BLM 

activities or who have participated in 

the past. 

Typically, the first step in the 

development or revision of an RMP is 

for the BLM to hold public scoping 

meetings to identify the primary issues 

that the BLM should consider and 

address in the RMP. If, for example, the 

public identifies tracts of land that are 

heavily used for recreational activities 

or that hold special environmental 

significance, the BLM may consider 

closing these tracts to oil and gas leasing 

or placing restrictions on development. 

Restrictions can include limiting the 

timing of oil and gas activities to avoid 

certain impacts, setbacks from sensitive 

resources, establishing limits on surface 

disturbance, and prohibiting surface 

occupancy entirely. Some areas, such as 

wilderness areas or land within an 

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incorporated city, are closed to leasing 

by law. In addition to public scoping, 

the BLM coordinates with state, county, 

and local governments, Indian tribes, 

and other Federal agencies. 

Once various land use options have 

been developed the BLM generally 

analyzes the environmental impacts of 

the alternatives through an 

Environmental Impact Statement (EIS), 

which offers additional opportunity for 

public involvement. For proposed land 

use decisions, such as keeping areas 

open for oil and gas leasing, 

environmental impacts are assessed 

based on a Reasonable Foreseeable 

Development (RFD) Scenario that 

projects the estimated levels and types 

of industry activity and the associated 

surface disturbance that might occur 

during the life of the RMP. Because the 

RMP and EIS generally cover all the 

Federal land and mineral estate 

administered by a BLM field office, the 

impact analysis is typically done on a 

broad scale. Mitigation measures 

developed through the draft RMP and 

EIS process can be implemented as 

stipulations on oil and gas leases. In 

addition to compliance with the 

National Environmental Policy Act 

(NEPA), the BLM must comply with the 

National Historic Preservation Act and 

the Endangered Species Act (ESA) and 

engage in a consultation process with 

the U.S. Fish and Wildlife Service under 

the ESA, if threatened or endangered 

species or critical habitat may be 

affected. 

Once a draft RMP and EIS are 

developed, the public has an additional 

opportunity to review and comment on 

the analysis and proposed mitigation 

measures in the EIS. When all 

comments have been considered, the 

BLM develops a final RMP and EIS. The 

Record of Decision finalizes the RMP, 

selecting a final action to be adopted 

from a reasonable range of alternatives 

and explaining the rationale for the 

decision. Once the Record of Decision is 

signed, the BLM makes all land use 

decisions, including oil and gas 

development decisions, in accordance 

with the RMP. 

Leasing Process. The next step in the 

oil and gas development process is the 

designation of parcels to be offered for 

lease, and an additional environmental 

review. Under existing regulations, the 

public may nominate tracts of land that 

they would like to see leased. It is far 

more common, however, for members of 

the industry to express interest in an 

area being offered for lease. The BLM 

first must ensure that the proposed 

tracts are under Federal jurisdiction and 

are open to leasing in accordance with 

the RMP. The next step is to conduct a 

second NEPA review—typically through 

an Environmental Assessment (EA)—to 

address potential impacts that could be 

caused by oil and gas development 

within the nominated area. The NEPA 

review conducted at the leasing stage 

‘‘tiers’’ from the RMP EIS. In other 

words, the issues, analysis of potential 

impacts, mitigation measures, and 

decisions in the RMP EIS are carried 

through to the NEPA review conducted 

at the leasing stage. 

An interdisciplinary team consisting 

of resource specialists develops the 

NEPA documentation. The 

interdisciplinary team visits the site to 

gather on-the-ground data on potential 

impacts and mitigation measures. After 

the site visit, an EA is drafted, including 

coordination with county, state, and 

Federal agencies, and consultation with 

Indian tribes, if applicable, in the area 

proposed for leasing. EAs are posted on 

the BLM Web site and are available in 

the public room(s) at BLM field offices 

for public review and comment, 

typically for a 30-day period. The BLM 

reviews and addresses comments 

received during that 30-day period 

when it finalizes the EA. Specific 

mitigation measures are developed in 

the context of the NEPA review and are 

included in a notice to potential bidders 

of an oil and gas lease at a lease sale. 

If the environmental review concludes 

with a finding that the proposed lease 

issuance would result in no significant 

impacts to the quality of the human 

environment (FONSI), then the lease 

parcel can be included in the next 

scheduled lease sale without any further 

NEPA analysis. Upon issuance by the 

BLM, the lease allows the operator to 

conduct operations on the lease. 

Exploration and development 

requirements. The BLM has existing 

regulations, including Onshore Oil and 

Gas Orders, to ensure that operators 

conduct oil and gas exploration and 

development in an environmentally 

responsible manner that protects other 

resources. These requirements will 

remain in place and will be 

supplemented by this final rule. 

Existing section 43 CFR 3162.3–1 and 

Onshore Order 1 require an operator to 

get approval from the BLM prior to 

drilling a well. The operator must 

submit an APD containing all of the 

information required by Onshore Order 

1. This includes a completed Form 

3160–3, Application for Permit to Drill 

or Re-Enter, a well plat, a drilling plan, 

a surface use plan, bonding information, 

and an operator certification. 

Upon receiving a drilling proposal on 

Federal lands, the BLM is required by 

existing section 3162.3–1(g) to post 

information for public inspection for at 

least 30 days before action to approve 

the APD. The information must include: 

The company/operator name; the well 

name/number; and the well location 

described to the nearest quarter-quarter 

section (40 acres), or similar land 

description in the case of lands 

described by metes and bounds, or maps 

showing the affected lands and the 

location of all tracts to be leased and of 

all leases already issued in the general 

area. Where the inclusion of maps in 

such posting is not practicable, the BLM 

provides maps of the affected lands 

available to the public for review. The 

public posting is in the office of the 

BLM authorized officer and in the 

appropriate surface managing agency 

office, if other than the BLM. Some field 

offices also make this information 

available on the field office Web site. 

The public may review the posted 

information and provide any input they 

would like the BLM to consider during 

its environmental analysis. If the public 

has questions and concerns regarding 

drilling proposals, they can meet with 

BLM staff and share those concerns. 

The drilling plan is a critical, 

detailed, and multi-faceted component 

of the APD that allows BLM engineers 

and geologists to complete an appraisal 

of the technical adequacy of, and 

environmental effects associated with, 

the proposed project. The drilling plan 

must include: 

• Geological information, including 

the name and estimated tops of all 

geologic groups, formations, members, 

and zones as well as the estimated 

depths and thickness of formations, 

members, or zones potentially 

containing usable water, oil, gas, or 

prospectively valuable deposits of other 

minerals that the operator expects to 

encounter, and their plans for protecting 

such resources. 

• Minimum specifications for 

blowout prevention equipment that will 

be used to keep control of well 

pressures encountered while drilling. 

• A description of the proposed 

casing program, including the size, 

grade, weight, and setting depth of each 

casing string. 

• Detailed information regarding the 

proposed cementing program, including 

the amount and types of cement the 

operator will use for each casing string, 

which is critical in establishing a barrier 

outside the casing between any 

hydrocarbon bearing zones and usable 

water zones. BLM engineers evaluate 

the proposed cementing program to 

ensure that the volume and strength of 

the cement is adequate to achieve the 

desired protections. 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16135 

• Information regarding the proposed 

drilling fluid and proposed testing, 

logging, and coring procedures. 

• An estimate of the expected bottomhole pressure and any anticipated 

abnormal pressures, temperatures, or 

potential hazards that the well may 

encounter. BLM geologists and 

engineers review this information to 

determine if any other anticipated 

hazards exist and to ensure that there 

will be adequate mitigation to address 

those hazards. 

• Other information that may be 

pertinent, including the directional 

drilling plan for deviated or horizontal 

wells so that BLM engineers can look for 

potential issues with existing wells. 

Just as the drilling plan allows the 

BLM to ensure the down-hole technical 

adequacy of the proposed project, the 

surface use plan provides the BLM with 

information needed to ensure safe 

operations, adequate protection of the 

surface resources, groundwater, and 

other environmental components in 

areas where the BLM manages the 

surface. 

The surface managing agency must 

approve surface use plans where the 

BLM does not manage the surface. The 

Bureau of Indian Affairs is considered to 

be the surface management agency for 

Indian lands. In the surface use plan, 

operators must also describe any Best 

Management Practices (BMPs) they 

expect to use. BMPs are mitigation 

measures applied to oil and natural gas 

drilling and production to help ensure 

that operators conduct energy 

development in an environmentally 

responsible manner. BMPs can protect 

water, wildlife, air quality, and 

landscapes. The BLM encourages 

operators to incorporate BMPs into their 

plans. Information concerning BMPs is 

available on the BLM’s Web site at: 

http://www.blm.gov/wo/st/en/prog/

energy/oil_and_gas/best_management_

practices.html. 

Where the BLM manages the surface, 

the operator’s surface use plan should 

incorporate the BLM’s ‘‘Surface 

Operating Standards and Guidelines for 

Oil and Gas Exploration and 

Development,’’ which is commonly 

referred to as ‘‘The Gold Book.’’ The 

BLM developed ‘‘The Gold Book’’ to 

assist operators by providing 

information on obtaining permit 

approval and conducting 

environmentally responsible oil and gas 

operations. It is available on the BLM’s 

Web site at: http://www.blm.gov/wo/st/

en/prog/energy/oil_and_gas/best_

management_practices/gold_book.html. 

In general, the surface use plan must 

include the following: 

• Location and description of, as well 

as maintenance plan for, existing and 

new roads the operator plans to use to 

access the proposed well. 

• A map showing all known wells, 

regardless of their status (producing, 

abandoned, etc.) within a one-mile 

radius of the proposed location so that 

the BLM can ensure the proposal does 

not conflict with any current surface 

use. The BLM also uses this well 

information to identify any potential 

downhole conflicts or issues between 

the existing wells and the proposed 

well. 

• A map or diagram showing the 

location of all production facilities and 

lines the operator will install if the well 

is successful (a producing well), as well 

as any existing facilities. 

• Information concerning the water 

supply, such as rivers, creeks, springs, 

lakes, ponds, and wells that the operator 

plans to use for drilling the well. 

• A written description of the 

methods and locations it proposes for 

safe containment and disposal of each 

type of waste materials that result from 

drilling the proposed well. The 

narrative must include plans for the 

eventual disposal of drilling fluids and 

any produced oil or water recovered 

during testing operations. 

• A diagram in the surface use plan 

of the proposed well site layout. 

• A plan for the surface reclamation 

or stabilization of all disturbed areas. 

Another component of the APD is 

proof of adequate bond coverage as 

required by existing 43 CFR 3104.1 for 

Federal lands and 25 CFR 211.24, 

212.24, and 225.30, for Indian lands. 

These regulations require the operator 

or the lessee to have an adequate bond 

in place prior to the BLM’s approval of 

the APD. If the BLM determines that the 

current bond amount is not sufficient, 

the BLM can require additional bond 

coverage. The BLM determines the need 

for bond increases by considering the 

operator’s history of violations, the 

location and depth of wells, the total 

number of wells involved, the age and 

production capability of the field, and 

any unique environmental issues. 

Upon receipt of a complete APD, the 

BLM will schedule an onsite inspection 

with the operator so that the BLM and 

operator may further identify sitespecific resource concerns and 

requirements not originally identified in 

the application. 

The onsite inspection team will 

include the BLM, a representative of any 

other surface management agency and 

the operator or permitting agent. When 

the onsite inspection is on private 

surface, the BLM will invite the surface 

owner to attend. The purpose of the 

onsite inspection is to discuss the 

proposal; determine the best location for 

the well, road, and facilities; identify 

site-specific concerns and potential 

environmental impacts associated with 

the proposal; and discuss the conditions 

of approval or possible environmental 

BMPs. If the BLM identifies resource 

conflicts, the BLM has the authority to 

require the operator to move surface 

facilities to locations that would reduce 

resource impacts while still allowing 

development of the leased minerals. 

Site-Specific Environmental Review. 

After the BLM has reviewed the 

operator’s proposed plans and 

conducted the onsite inspection, the 

BLM will prepare an environmental 

document in conformance with NEPA 

and its implementing regulations. The 

extent of the environmental analysis 

process and the time frame for issuance 

of a decision will depend upon the 

complexity of the proposed action and 

resulting analysis, the significance of 

the environmental effects disclosed, and 

the completion of appropriate 

consultation processes. Regardless of 

the complexity of the proposed action, 

the environmental document will 

always consider the impacts to cultural 

resources, endangered species, surface 

water, and groundwater. An 

interdisciplinary team of BLM resource 

specialists will conduct the analysis. 

The environmental analysis may be 

conducted for a single well, a group of 

wells, or for an entire field. The public 

is welcome to provide input to the BLM 

for inclusion in the analysis. As 

discussed previously, the BLM posts 

notices of all Federal APDs for public 

inspection in the authorizing office. For 

large projects, such as field 

development environmental 

assessments or environmental impact 

statements, the BLM will go through 

public scoping and may issue a draft 

analysis for public comment prior to 

completing the final analysis and 

issuing a decision. 

The environmental analysis will 

identify potential impacts from the 

proposed action. The BLM will develop 

any necessary conditions of approval to 

mitigate those potential impacts. If 

unacceptable impacts are identified, the 

BLM will ask the operator to modify its 

proposal, or the BLM may deny the 

application. The BLM will attach the 

conditions of approval to the approved 

APD that the operator must follow. 

Examples of conditions of approval 

include road improvements, additional 

erosion control, or seasonal restrictions 

on some activities. In cases where the 

BLM manages the surface, the BLM may 

also require baseline water testing prior 

to drilling. 

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16136 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

Compliance with Onshore Oil and 

Gas Order No. 2. Upon BLM’s approval 

of an APD, the operator may commence 

drilling of the well. In addition to the 

approved plan and the conditions of 

approval, the operator must also comply 

with the requirements of Onshore Oil 

and Gas Order No. 2, (Onshore Order 2), 

which details the BLM’s uniform 

national standards for the minimum 

levels of performance expected from 

operators when conducting drilling 

operations on Federal and Indian lands. 

Many of the requirements of Onshore 

Order 2 ensure the protection of usable 

water. 

Onshore Order 2 also requires the 

operator to: 

• Conduct the proposed casing and 

cementing programs as approved to 

protect and isolate all usable water 

zones, lost circulation zones, 

abnormally pressured zones, and any 

prospectively valuable deposits of 

minerals. It also requires the operator to 

report all indications of usable water. 

• Employ technical measures to 

center the casing in the drilled hole 

prior to cementing in order to ensure 

wellbore integrity. It also requires the 

operator to cement the surface casing up 

to the surface either during the primary 

cement job or by remedial cementing, 

which ensures that all usable water 

zones behind the surface casing are 

isolated and protected. 

• Wait until the cement for all casing 

strings achieves a minimum of 500 

pounds per square inch (psi) 

compressive strength at the casing shoe 

prior to drilling out the casing shoe and 

utilize proper cementing techniques. 

• Pressure test the casing prior to 

drilling out the casing shoe to ensure 

the integrity of the casing. The operator 

must also conduct a pressure integrity 

test of each casing shoe on all 

exploratory wells, and on that portion of 

any well approved for a 5,000 psi 

blowout preventer. The pressure test 

ensures the integrity of the cement 

around the casing shoe. 

In addition, Onshore Order 2 

identifies the minimum requirements 

for blowout prevention equipment and 

the minimum standards for testing the 

equipment. Proper sizing, installation, 

and testing of the blowout prevention 

equipment ensures that the operator 

maintains control of the well during the 

drilling process, which is necessary for 

protection of usable water zones. 

Post-Approval Inspections and 

Reporting. The BLM conducts 

inspections of drilling operations to 

ensure that operators comply with the 

Onshore Order 2 drilling regulations, 

the approved permit, and the conditions 

of approval. The BLM drilling 

inspections consist of two general types 

of inspections: Technical and 

environmental. The BLM petroleum 

engineering technicians conduct 

technical inspections of the drilling 

operations such as witnessing the 

running and cementing of the casing, 

witnessing the testing of the blowout 

prevention equipment, and detailed 

drilling rig inspections. Such 

inspections also include review of 

documentation such as the third-party 

cementing job ticket that describes the 

cementing operation, including the type 

and amount of cement used, the cement 

pump pressures, and the observation of 

cement returns to the surface, if 

applicable. 

The BLM natural resource specialists 

conduct environmental inspections of 

drilling operations that focus primarily 

on the surface use portion of the 

approved drilling permit. This includes 

inspection of the access road, the well 

pad, and pits. While the BLM does not 

have the budget or personnel to inspect 

every drilling operation on Federal and 

Indian minerals, the BLM conducts 

inspections in accordance with an 

annual risk-based strategy to ensure 

compliance with the regulations, lease 

stipulations, and permits. 

Within 30 days after the operator 

completes a well, the operator is 

required by existing regulations to 

submit a BLM Well Completion or 

Recompletion Report and Log (Form 

3160–4), which provides drilling and 

completion information. Similar to 

completion of a new well, an existing 

well can be recompleted to restore 

productivity and thus produce oil or gas 

which would have otherwise been 

abandoned. This document includes the 

actual casing setting depths and the 

amount of cement the operator used in 

the well, together with information 

regarding the completion interval 

between, for example, the top and 

bottom of the formation, the perforated 

interval, and the number and size of 

perforation holes. The operator is also 

required to submit copies of all electric 

and mechanical logs. The BLM reviews 

this information to ensure that the 

operator set the casing and pumped the 

cement according to the approved 

permit. 

Compliance with Onshore Oil and 

Gas Order No. 7. Once a well goes into 

production, water is often produced 

with the oil and gas. The water tends to 

be of poor quality and is not generally 

suitable for drinking, livestock, or other 

uses and, therefore, must be disposed of 

properly. Onshore Oil and Gas Order 

No. 7 (Onshore Order 7) regulates the 

disposal of produced water. Under 

Onshore Order 7, operators must apply 

to the BLM for authorization to dispose 

of produced water by injecting the water 

back into a suitable formation, by 

storing it in pits, or by other methods 

approved by the BLM. If the water will 

be stored in pits, the BLM requires 

specific design standards to ensure the 

water does not contaminate the 

environment or pose a threat to public 

health and safety. 

Post-Drilling Inspections. After a well 

has been drilled and completed, the 

BLM continues to inspect the well until 

it has been plugged and abandoned, and 

the surface has been rehabilitated. 

During the production phase of the well, 

the BLM inspections focus on two 

primary issues: Production and the 

environment. The Federal Government 

(Federal leases) or an Indian tribe or 

individual Indian allottee (Indian 

leases) receive a royalty on the oil and 

gas removed or sold from the lease 

based on the volume, quality, and value 

of the oil and gas. Royalties from 

Federal leases are shared with the state 

as provided by statute. Production 

inspections are conducted by the BLM 

to ensure the volume and quality of the 

oil and gas is accurately measured and 

properly reported. Environmental 

inspections are conducted by the BLM 

to ensure that wellpads and facilities are 

in compliance with regulations, 

Onshore Orders, and approved permits. 

Environmental inspections include 

ensuring that pits are properly 

constructed, maintained, and protected 

from wildlife; identifying leaking wells 

or pipelines; ensuring that the wellsite 

and facilities are properly maintained; 

and ensuring that proper erosion 

controls and rehabilitation measures are 

in place. 

Well Plugging, Abandonment and Site 

Restoration. When a well has reached 

the end of its economic life, Federal 

regulations require that it be plugged 

and abandoned to prevent oil and gas 

from leaking to the surface or 

contaminating water bearing zones or 

other mineral zones. An operator may 

request well abandonment or the BLM 

may require it. In either case, the 

operator must submit a proposal for 

well plugging, including the length, 

location, type of cement, and placement 

method to be used for each plug. The 

operator must also submit a plan to 

rehabilitate the surface once the well 

has been plugged. The goal of surface 

rehabilitation is to remove obvious 

visual evidence of the pad and to 

promote the long-term stability of the 

site and vegetation. 

The BLM inspects both well plugging 

and surface restoration. Well plugging 

inspections are completed to ensure the 

plugs are set in accordance with the 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16137 

procedure approved by the BLM. The 

inspector will witness the depth and 

volume of cement used in a plug as well 

as the physical verification of the top of 

a plug. When an operator has completed 

surface restoration, it will notify the 

BLM or the surface management agency. 

The surface protection specialists of the 

BLM or of the surface management 

agency will inspect the site to ensure 

the restoration is adequate. Once the 

BLM or the surface management agency 

is satisfied with the restoration efforts, 

the BLM will approve the operator’s 

Final Abandonment Notice. 

The regulations and Onshore Orders 

that have been in place to this point 

have served to provide reasonable 

certainty of environmentally responsible 

development of oil and gas resources on 

public lands, but are in need of revision 

as extraction technology has advanced. 

The final rule will complement these 

existing rules by providing further 

assurance of wellbore integrity, 

requiring with limited exception public 

disclosure of chemicals used in 

hydraulic fracturing, and ensuring safe 

management of recovered fluids. Taken 

together these regulations establish 

baseline environmental safeguards for 

hydraulic fracturing operations across 

all public and Indian lands. 

II. Discussion of the Final Rule and 

Comments on the Proposed Rules 

As was discussed in the initial and 

supplemental proposed rules, the BLM 

is revising its hydraulic fracturing 

regulations, found at 43 CFR 3162.3–2, 

and adding a new section 3162.3–3. 

Existing section 3162.3–3 is retained 

and renumbered. As stewards of the 

public lands and minerals and as the 

Secretary’s regulator for operations on 

oil and gas leases on both public and 

Indian lands, the BLM has evaluated the 

increased use of hydraulic fracturing 

practices over the last decade and 

determined that the existing rules for 

hydraulic fracturing require updating. 

The FLPMA directs the BLM to 

manage the public lands so as to prevent 

unnecessary or undue degradation, and 

to manage those lands using the 

principles of multiple use and sustained 

yield. The FLPMA defines multiple use 

to mean, among other things, a 

combination of balanced and diverse 

resource uses that takes into account 

long-term needs of future generations 

for renewable and non-renewable 

resources. The FLPMA also provides 

that the public lands be managed in a 

manner that will protect the quality of 

their resources, including, but not 

limited to, ecological, environmental, 

and water resources. The Mineral 

Leasing Act and the Mineral Leasing Act 

for Acquired Lands authorize the 

Secretary to lease Federal oil and gas 

resources, and to regulate oil and gas 

operations on those leases, including 

surface-disturbing activities. 

The Act of March 3, 1909, the Indian 

Mineral Leasing Act and the Indian 

Mineral Development Act assign 

regulatory authority to the Secretary 

over Indian oil and gas leases on trust 

lands (except those excluded by statute, 

i.e., the Crow Reservation in Montana, 

the ceded lands of the Shoshone 

Reservation in Wyoming, the Osage 

Reservation in Oklahoma, and the coal 

and asphalt lands of the Choctaw and 

Chickasaw Tribes in Oklahoma). The 

Secretary has delegated to the BLM her 

authority to oversee operations on 

Indian mineral leases through the 

Departmental Manual (235 DM 1.K), and 

the Bureau of Indian Affairs’ regulations 

provide that 43 CFR part 3160 applies 

to oil and gas operations on Indian 

lands. See 25 CFR 211.4, 212.4, and 

225.4. The Secretary also approved the 

authorities section of the regulations 

which give the BLM authority under the 

Indian minerals statutes. 

As discussed in the background 

section of this preamble, the increased 

use of well stimulation activities over 

the last decade has generated concerns 

among the public about hydraulic 

fracturing and about the chemicals used 

in hydraulic fracturing. This final rule is 

intended to increase transparency for 

the public regarding the fluids used in 

the hydraulic fracturing process, 

provide assurance that wellbore 

integrity is maintained throughout the 

fracturing process and ensure that the 

fluids that flow back to the surface from 

hydraulic fracturing operations are 

properly stored, disposed of, or treated. 

The BLM’s engineers and field managers 

have decades of experience exercising 

oversight of these wells during the 

evolution of this technology. This 

expertise, together with input from the 

public, industry, state, academic and 

other experts discussed below, forms 

the basis for the decision that new rules 

are needed and for the requirements 

contained in this rule. 

The following chart explains the 

major changes between the 

supplemental proposed rule and this 

final rule. A similar chart explaining the 

differences between the proposed and 

supplemental proposed rules appears in 

the supplemental proposed rule at 78 

FR 31641 and a chart explaining the 

differences between the existing 

regulations and the original proposed 

rule appears in the proposed rule at 77 

FR 27694. 

Supplemental 

proposed regulation Final regulation Substantive changes 

43 CFR 3160.0–5 Definitions .......... 43 CFR 3160.0–5 Definitions ........ This final rule makes a series of changes to the definitions section. 

The term ‘‘master hydraulic fracturing plan’’ is added. The definition 

of a cement evaluation log is moved from § 3162.2–3(e)(2) to the 

definitions section. The term ‘‘confining zone’’ is now defined because that term is used in revised § 3162.3–3(d). The term ‘‘refracturing’’ is deleted from this section and the rest of the rule. The 

term ‘‘usable water’’ is updated to remove the requirement to identify usable water only via drill log. The final rule also clarifies the 

definition of ‘‘usable water’’. 

43 CFR 3162.3–2 Subsequent Well 

Operations.

43 CFR 3162.3–2 Subsequent 

Well Operations.

Paragraph (a) of this section is modified slightly by removing the 

phrase ‘‘the operator’’ because it is redundant. 

43 CFR 3162.3–3(a) Hydraulic 

Fracturing.

43 CFR 3162.3–3(a) Subsequent 

Well Operations; Hydraulic Fracturing.

The final rule clarifies the application of this rule to wells at various 

stages of completion on the publication and effective date, and 

clarifies what sections of the rule apply based on a table which distinguishes leases with approved APDs from leases without approved APDs, as well as leases with approved APDs that do not 

have wells spudded. 

43 CFR 3162.3–3(b) Isolation of 

Usable Water to Prevent Contamination.

43 CFR 3162.3–3(b) Isolation of 

Usable Water to Prevent Contamination.

The term ‘‘refracturing’’ is deleted. 

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Supplemental 

proposed regulation Final regulation Substantive changes 

43 CFR 3162.3–3(c) When an Operator Must Submit Notification 

for Approval of Hydraulic Fracturing.

43 CFR 3162.3–3(c) How an Operator Must Submit a Request 

for Approval of Hydraulic Fracturing.

Paragraphs (c)(1) and (2) of this section are revised non-substantively and for clarity. Paragraph (c)(3) is revised to remove references to refracturing. As in the supplemental proposed rule, the 

operator may submit the hydraulic fracturing proposal either in the 

APD or as an NOI. The final rule removes ‘‘type wells’’ from this 

section. In the final rule a request to hydraulically fracture can be 

submitted for a group of wells in a master hydraulic fracturing plan. 

Paragraph (c)(4) is added to address and clarify when an operator 

must submit a new NOI. 

43 CFR 3162.3–3(d) What the Notice of Intent Sundry Must Include.43 CFR 3162.3–3(d) What a Request for Approval of Hydraulic 

Fracturing Must Include.

Consistent with other changes in this rule, the final rule replaces the 

procedure for submitting an NOI for multiple wells through a type 

well submission, and instead allows submission of a master hydraulic fracturing plan. Paragraph (d)(1) is revised to require specific information regarding wellbore geology, including information 

regarding the formation into which hydraulic fracturing fluids are to 

be injected, the estimated depths of the confining zones and occurrences of usable water. Paragraph (d)(2) is revised to require a 

map showing information regarding known or suspected faults and 

fractures. Paragraph (d)(4) is also revised to require submission of 

a map showing information about the trajectory of the wellbore and 

estimated direction and length of the fractures that will be propagated and all existing wellbore trajectories for all wells within onehalf mile of the wellbore that will be hydraulically fractured. 

43 CFR 3162.3–3(d)(2) ................... 43 CFR 3162.3–3(d)(2) ................. The final rule deletes the requirement to submit occurrences of usable water by use of a drill log and instead allows flexibility in how to 

obtain the information. 

43 CFR 3162.3–3(d)(3) ................... 43 CFR 3162.3–3(d)(3) ................. The final rule eliminates the requirement to submit the proposed 

measured depth of perforations or the open hole interval and estimated pump pressures and makes it clear that the wells referred to 

in this provision are water supply wells. 

43 CFR 3162.3–3(d)(4) ................... 43 CFR 3162.3–3(d)(4) ................. The final rule combines paragraphs (ii) and (iii) into a revised paragraph (ii) to read ‘‘the maximum anticipated surface pressure that 

will be applied during the hydraulic fracturing process.’’ The revised 

terminology encompasses the intent of the previous two paragraphs. Supplemental proposed rule paragraph (iv) is now paragraph (iii) and is revised in the final rule, and the word ‘‘calculated’’ 

is deleted, to reinforce the lack of certainty of the information in the 

APD or NOI at this stage of operations. Supplemental proposed 

rule paragraph (v) is deleted and replaced with a revised paragraph (iv), which seeks the estimated minimum vertical distance to 

the nearest usable water aquifer above the fracture zone. New 

paragraph (v) asks for the measured depth of the proposed perforated or open hole interval. Both the old paragraph (v) and the 

new paragraph (iv) aim to provide guidance to the BLM on protecting usable water zones. 

43 CFR 3162.3–3(d)(5) ................... 43 CFR 3162.3–3(d)(5) ................. The final rule eliminates some of the specific details of the fluid recovery plan, focusing on estimated volume, proposed handling 

methods and proposed disposal methods. Further, the timeline is 

being clarified to better reflect the scope of the plan. This paragraph is also revised by adding a provision asking for information 

about the handling of recovered fluids between the time of the start 

of hydraulic fracturing operations and the approval of the disposal 

of produced fluids under BLM’s regulations, which are currently 

contained in existing Onshore Order 7. Paragraph (i) is revised by 

eliminating the three circumstances that were listed where the volume of recovered fluid must be estimated, but keeping the requirement to estimate the volume of fluid to be recovered. New paragraph (ii) asks for the proposed methods of handling recovered 

fluids by cross reference to paragraph (h) of this section, which requires the use of rigid enclosed, covered or netted and screened 

above-ground tanks to store these fluids (with a limited exception 

for the use of lined pits). Paragraph (iii) of this section is revised by 

making clear the methods of handling recovered fluids that must be 

described in the application. 

None ................................................ 43 CFR 3162.3–3(d)(6) ................. The final rule includes a requirement for a surface use plan of operations if the hydraulic fracturing operation would cause additional 

surface disturbance. By reference to paragraph (e), it requires documentation that an adequate cement job occurred for all casing 

strings designed to isolate usable water. 

43 CFR 3162.3–3(d)(6) ................... 43 CFR 3162.3–3(d)(7) ................. Because of new paragraph (d)(6), the former paragraph (d)(6) is renumbered as paragraph (d)(7), and is revised to make it clear that 

the requirement may apply to an APD as well as a NOI. 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16139 

Supplemental 

proposed regulation Final regulation Substantive changes 

43 CFR 3162.3(e) Monitoring of 

Cementing Operations and Cement Evaluation Log Prior to Hydraulic Fracturing.

43 CFR 3162.3–3(e) Monitoring 

and Verification of Cementing 

Operations Prior to Hydraulic 

Fracturing.

The title of this section is revised to better reflect the content of the 

final rule. 

43 CFR 3162.3–3(e)(1) ................... 43 CFR 3162.3–3(e)(1) ................. This paragraph is revised to make it clear that the information request is for any casing string used to isolate usable water zones. 

The section is also revised to require that the information be submitted to the authorized officer 48 hours prior to the start of hydraulic fracturing operations unless the authorized officer approves 

a shorter time. 

43 CFR 3162.3–3(e)(2) ................... 43 CFR 3162.3–3(e)(2) ................. New paragraph (e)(2) replaces supplemental proposed rule paragraph (e)(2) and requires that prior to hydraulic fracturing operations the operator must determine and document that there is 

adequate cement for all casing strings to isolate usable water. For 

surface casing, the operator must observe cement returns to the 

surface and document any indications of inadequate cement following the new requirements of this paragraph. For intermediate or 

production casing, if the casing is not cemented to the surface, the 

operator must run a CEL demonstrating that there is at least 200 

feet of adequately bonded cement protecting the deepest usable 

water zone. If the casing is cemented to the surface, then the operator must follow the same requirements as for surface casing established earlier in this section. 

43 CFR 3162.3–3(e)(3), (e)(4), and 

(e)(5).

43 CFR 3162.3–3(e)(3) ................. Final paragraph (3) combines revised supplemental proposed rule 

paragraphs (3), (4), and (5). For any well where there is an indication of inadequate cement, the operator must follow the provisions 

of this paragraph. The operator must notify the BLM of the inadequate cement within 24 hours of discovering it (paragraph (3)(i)) 

and submit a plan to the BLM requesting approval of remedial action to achieve adequate cement (paragraph (3)(ii)). This section 

also addresses emergency situations where an operator may request oral approval of remedial action to correct inadequate cement. Such oral approvals must be followed by written notice within 

5 business days following oral approval. The operator must also 

verify that the remedial action was successful with a CEL or other 

method BLM approves in advance (paragraph (3)(iii)). Consistent 

with the supplemental proposed rule, the operator must submit a 

subsequent report for the remedial action including a certification 

that the remedial action followed the approved plan and was successful (paragraph (3)(iv)). Under paragraph (3)(v), the operator 

must submit to the BLM the results of the CEL or other testing 

method that showed that the remedial action was successful at 

least 72 hours before starting hydraulic fracturing operations. 

43 CFR 3162.3–3(f) Mechanical Integrity Testing Prior to Hydraulic 

Fracturing.

43 CFR 3162.3–3(f) Mechanical 

Integrity Testing Prior to Hydraulic Fracturing.

Paragraph (1) of this section is revised to include the words ‘‘that will 

be applied during the hydraulic fracturing process,’’ to clarify the 

timing of the requirement. Paragraph (2) of this section is revised 

by replacing the word ‘‘treating’’ with the word ‘‘surface’’ in the second sentence of this paragraph. 

43 CFR 3162.3–3(g) Monitoring 

and Recording During Hydraulic 

Fracturing.

43 CFR 3162.3–3(g) Monitoring 

and Recording During Hydraulic 

Fracturing.

This paragraph has been revised to delete the term ‘‘refracturing,’’ 

and clarifies the actions that operators must take when pressure 

within the annulus increases by more than 500 pounds per square 

inch as compared to the pressure immediately preceding the stimulation. 

43 CFR 3162.3–3(h) ....................... 43 CFR 3162.3–3(h) Management 

of Recovered Fluids.

This section has undergone numerous changes. The final rule requires that fluids recovered be stored in above-ground tanks prior 

to disposal under BLM’s regulations (currently in Onshore Order 7). 

Paragraphs (1) and (2) specify the very limited conditions under 

which an authorized officer may approve a lined pit in lieu of a 

tank. 

43 CFR 3162.3–3(i) Information 

that Must be Provided to the Authorized Officer After Completed 

Operations.

43 CFR 3162.3–3(i) and (i)(1) Information that Must be Provided 

to the Authorized Officer After 

Hydraulic Fracturing is Completed.

The heading of this section is revised to make it clearer. Paragraph 

(i)(1) of this section is also revised to require the operator to provide information about each additive in the hydraulic fracturing 

fluid. This will help to account for proppants as well as chemical 

additives. 

43 CFR 3162.3–3(i)(2) .................... 43 CFR 3162.3–3(i)(2), (i)(3), and 

(i)(5).

This section has been revised to seek only the actual sources and locations of the water used in the hydraulic fracturing fluid. The pressure information requested in the supplemental proposed rule is 

covered in the final rule by paragraph (3) and the depth of perforations and open hole interval is part of new paragraph (5). 

43 CFR 3162.3–3(i)(3) .................... 43 CFR 3162.3–3(i)(3) .................. The final rule seeks the maximum surface pressure rather than the 

actual surface pressure and no longer seeks the flush rate or the 

final pump pressure concentration in the fracturing fluid. 

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16140 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

Supplemental 

proposed regulation Final regulation Substantive changes 

43 CFR 3162.3–3(i)(4) .................... 43 CFR 3162.3–3(i)(4) .................. This section requires the report to include the actual, estimated, or 

calculated fracture length, height, and direction. This section remains as proposed. 

None ................................................ 43 CFR 3162.3–3(i)(5) .................. New paragraph (5) requires information previously contained in paragraph (2), regarding the actual measured depth of perforations or 

the open-hole interval. 

None ................................................ 43 CFR 3162.3–3(i)(6) .................. New paragraph (6) requires operators to report the total volume of 

fluid recovered between the time that hydraulic fracturing is completed and when the operator starts to report water produced from 

the well to Office of Natural Resources Revenue (ONRR). 

43 CFR 3162.3–3(i)(5)(i) ................. 43 CFR 3162.3–3(i)(7) .................. The final rule revises this renumbered paragraph to clearly outline the 

timeframe for reporting information pertaining to fluid recovery. 

43 CFR 3162.3–3(i)(5)(ii) ................ 43 CFR 3162.3–3(i)(7)(i) ............... This final section is renumbered, but is similar to the supplemental 

proposed rule. 

43 CFR 3162.3–3(i)(5)(iii) ............... 43 CFR 3162.3–3(i)(7)(ii) .............. The final rule would simplify this section by removing the reference to 

Onshore Order No. 7 and seek information on disposal method, 

such as injection, recycling, or off-lease storage. 

43 CFR 3162.3–3(i)(6) .................... Deleted .......................................... This section is deleted and is unnecessary because the Authorized 

Officer can always require an explanation of any deviation under 

(i)(10) of this section. 

43 CFR 3162.3–3(i)(7) .................... 43 CFR 3162.3–3(i)(8) .................. The final rule renumbers this section. Paragraphs (8)(ii) and (8)(iii) 

are revised to make it clear that the provisions only apply to hydraulic fracturing fluid constituents once they arrive on the lease. 

43 CFR 3162.3–3(i)(8) .................... 43 CFR 3162.3–3(i)(9) .................. The final rule renumbers this section. The well logs and records of 

adequate cement bonds, including the cement monitoring report 

and any cement evaluation log, are no longer required to be submitted under this section because this information is covered either 

in the APD or NOI under paragraph (e) of this section. 

43 CFR 3162.3–3(j) Identifying Information Claimed to be Exempt 

from Public Disclosure.

43 CFR 3162.3–3(j) Identifying Information Claimed to be Exempt 

from Public Disclosure.

The final rule at paragraph (j)(1) strengthens the affidavit provisions 

to ensure that operators fully describe and attest to the basis for 

their claim of exemption from public disclosure for trade secrets. 

The affidavit must be signed by a corporate officer or the equivalent responsible official of the operator. The affidavit must identify 

and provide contact information for the owner of the withheld information, if it is not the operator. New paragraph (j)(2) provides that 

if the operator relies on facts supplied by another entity, it must include an affidavit from a responsible official of that entity verifying 

those facts. Former paragraph (j)(2) has been renumbered (j)(3) 

without substantive change. Former paragraph (j)(4) has been renumbered as paragraph (j)(5) and is revised by requiring that the 

operator maintain records of the information claimed to be exempt 

from disclosure until the later of the BLM’s approval of a final abandonment notice, or 6 years from completion of hydraulic fracturing 

operations for Indian lands, or 7 years from completion of hydraulic 

fracturing operations for Federal lands, as is consistent with applicable law. Any subsequent operator is responsible for maintaining 

access to those records. The final rule also adds a new paragraph 

(j)(6) to this section requiring the operator to submit the chemical 

family name or other similar descriptor for information claimed to 

be exempt from disclosure. 

43 CFR 3162.3–3(k) Requesting a 

Variance from the Requirements 

of this Section.

43 CFR 3162.3–3(k) Requesting a 

Variance from the Requirements 

of this Section.

The final rule revises the variance provisions to allow for individual 

variances and state/tribal variances in different sections. Most of 

the substantive information in this section has not changed, but 

has been re-organized and revised for clarity. One revision to this 

section is made to make the rule consistent with Onshore Order 1 

by clarifying that the decision on whether to approve a variance request is not administratively appealable to either the State Director 

or to the Interior Board of Land Appeals under 43 CFR part 4. 

Section-by-Section Discussion of the 

Revised Proposed Rule and Discussion 

of Comments 

Comments Addressed in This Rule 

In this preamble, the BLM discusses 

many of the comments received on the 

supplemental and proposed rules. 

Commenters provided detailed and 

helpful information that assisted in 

framing the issues and ultimately in 

producing this final rule. The 

Department does not address every 

comment in this final rule, because the 

changes in this rule have mooted some 

comments on the initial proposed rule 

and the supplemental proposed rule. 

Other comments were not central to the 

evaluation the BLM has undertaken, and 

thus discussion of those few comments 

would not contribute to the public’s 

understanding of the reasons for the 

final rule. 

Additionally, not every change in the 

final rule responds to a specific 

comment. Some revisions clarify the 

final rule, and still other revisions allow 

this final rule to be more effective or 

reduce inefficiencies. 

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Section Discussion 

As an administrative matter, this rule 

would amend the authorities section for 

the BLM’s oil and gas operations 

regulations at 43 CFR 3160.0–3 to 

include the FLPMA. Section 310 of the 

FLPMA authorizes the Secretary of the 

Interior to promulgate regulations to 

carry out the purposes of the FLPMA 

and other laws applicable to the public 

lands. See 43 U.S.C. 1740. This 

amendment would not be a major 

change and would have no effect on 

lessees, operators, or the public. 

Section 3160.0–5 Definitions 

This section defines terms related to 

the regulation and the hydraulic 

fracturing process. The terms annulus, 

bradenhead, cement evaluation log, 

confining zone, hydraulic fracturing, 

hydraulic fracturing fluid, and proppant 

are used to describe the requirements of 

the rule. The term ‘‘master hydraulic 

fracturing plan’’ (MHFP) would allow 

operators to gain certain efficiencies in 

submitting information to the BLM. The 

actual process is explained in sections 

3162.3–3(c) and (d). 

The final rule incorporates several 

changes to the definitions in section 

3160.0–5 from the supplemental 

proposed rule. The definition of cement 

evaluation log is added to this section 

by moving it from section 3162.2–3(e)(2) 

in the supplemental proposed rule to 

the definitions section of the final rule. 

Because the final rule uses the term 

several times, the BLM decided to add 

the definition to this section. 

The term ‘‘master hydraulic fracturing 

plan’’ is added to take the place of 

portions of the type well approval in 

section 3162.3–3(d) of the proposed 

rule. The final rule retains the ability for 

operators to submit hydraulic fracturing 

proposals at the APD or NOI stage for a 

group of similar wells with a single 

submission, including the information 

regarding geology, etc., required in 

sections 3162.3–3(d)(1) through (d)(7) of 

this rule. The BLM believes that this 

will streamline the permitting process 

without sacrificing the quality of the 

review. As a matter of current practice, 

many oil and gas operators use the APD 

review and approval process to satisfy 

other BLM approval requirements. For 

example, the construction of a road to 

access a drilling location or a pipeline 

to transport production from a well 

requires a right-of-way (ROW) in certain 

cases. Many operators submit their plan 

of development for their proposed 

access road or pipeline and a ROW 

application with their APD. The BLM 

performs its review of the ROW 

application at the same time it is 

reviewing the APD. An MHFP may not 

be used for the information required to 

demonstrate well integrity in section 

3162.3–3(e). As discussed later, the 

‘‘type well’’ concept has been 

eliminated and each well will be 

required to be demonstrated to meet the 

performance standards in this rule. 

In addition, the requirement that an 

MHFP only apply to wells in the same 

field is eliminated primarily because the 

term ‘‘field’’ is not well defined. Instead, 

in the final rule, an MHFP applies to 

any well where the geologic 

characteristics are substantially similar. 

The geographic area for which an MHFP 

applies will be at the discretion of the 

field office. The MHFP is similar in 

concept to the Master Development Plan 

(MDP) allowed in Onshore Order 1, 

although the use of one does not 

necessarily depend upon the use of the 

other. The MHFP is specific to the 

technical aspects of hydraulic fracturing 

of a group of wells; whereas, the MDP’s 

purposes include encouraging logical 

field development and ensuring 

consideration of the environmental 

effects associated with development of 

the field in the accompanying NEPA 

analysis and documentation. The MHFP 

and MDP can apply to different groups 

of wells. 

The term ‘‘hydraulic fracturing’’ was 

also modified by adding the phrase ‘‘by 

applying fluids under pressure.’’ This 

change is based on comments seeking 

clarification of the types of operations 

that fall under the scope of this rule. 

The term ‘‘type well’’ was eliminated. 

The BLM determined that the use of a 

type well CEL as a model for other wells 

that were geologically similar was not a 

statistically valid approach for ensuring 

wellbore integrity. Because geologic 

conditions and drilling procedures can 

vary significantly from well to well, 

sometimes even for wells drilled from 

the same pad, a CEL on a single sample 

well cannot reliably be extrapolated to 

other wells with any level of 

confidence. Therefore, the ‘‘type well’’ 

concept, as it applied to CELs, is 

eliminated in the final rule. 

The term ‘‘confining zone’’ is added 

to the final rule because the BLM is 

requiring the operator to identify both 

the confining zone and any known 

faults or fractures that transect the 

confining zone in the APD or NOI for 

hydraulic fracturing approval. The 

definition of confining zone is based on 

the U.S Environmental Protection 

Agency (EPA)’s definition under the 

Underground Injection Control (UIC) 

program, modified to apply specifically 

to hydraulic fracturing. 

The term ‘‘refracturing’’ was 

eliminated from the final rule because 

the requirements for permitting, 

performing, monitoring, and reporting 

hydraulic fracturing operations are 

identical whether the well is 

hydraulically fractured for the first time 

or any subsequent stimulation. 

Usable Water 

The BLM made several modifications 

to the definition of the term ‘‘usable 

water’’ in response to comments 

received. 

The first change in the ‘‘usable water’’ 

definition was to eliminate paragraph 

(2) from the definition in the 

supplemental proposed rule because it 

would be unreasonable to expect an 

operator to know that other users could 

be using an aquifer for agricultural or 

industrial purposes and because an 

operator would have no way of knowing 

if other users could be adversely 

affected by hydraulic fracturing. 

Decisions on those matters are for state 

or tribal water regulators, not the BLM. 

Thus, paragraph (1)(ii) in the final rule 

defers to State (for Federal lands) or 

tribal (for Indian lands) determinations 

that groundwater that does not meet the 

definition of ‘‘underground sources of 

drinking water’’ (USDWs) in EPA’s 

regulations are nonetheless sources of 

drinking water that must be protected. 

The other change was to reorganize the 

clauses in the definition to separate 

those items that would be deemed 

usable water from those items that 

would not be deemed usable water. 

Numerous commenters were confused 

about the threshold for Total Dissolved 

Solids (TDS) in usable water. Prior to 

the publication of this rule, BLM 

regulations (existing section 3162.5– 

2(d)) require the operator to ‘‘isolate 

freshwater-bearing and other usable 

water containing 5,000 ppm or less of 

total dissolved solids . . .,’’ and 

Onshore Oil and Gas Order No. 2, 

Drilling Operations on Federal and 

Indian Oil and gas leases (53 FR 46798) 

(Onshore Order 2), section III. B. 

requires casing and cement to ‘‘protect 

and/or isolate all usable water zones.’’ 

Usable water is defined in section II.Y 

of Onshore Order 2 as ‘‘generally those 

waters containing up to 10,000 ppm of 

total dissolved solids.’’ The requirement 

in the CFR was inconsistent with the 

requirement in Onshore Order 2. 

This rule corrects the inconsistency 

between the two by removing the 5,000 

ppm standard in 43 CFR 3162.5–2(d) 

and replacing it with language that is 

consistent with Onshore Order 2. The 

requirement to protect and/or isolate 

usable water generally containing up to 

10,000 ppm of TDS has been in effect 

since 1988, when Onshore Order 2 

became effective. This rule does not 

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5For example, any activity authorized under this 

rule may also require an aquifer exemption for 

injection activities in the same zone if that zone is 

regulated by the EPA under the SDWA, even where 

the zone is not considered to contain usable water 

under this rule. 

substantially modify the requirements 

in Onshore Order 2, although it clarifies 

the term by incorporating specific 

inclusions and exclusions as to what 

constitutes usable water. The final rule 

keeps the 10,000 ppm threshold from 

Onshore Order 2 as the primary 

determining factor for what constitutes 

usable water. 

Because of the inconsistency between 

the supplemental proposed rule and 

existing codified regulations, some 

commenters were under the impression 

that this rule was increasing the level of 

protection for usable water from 5,000 

ppm to 10,000 ppm, while other 

commenters believed that this rule was 

proposing to decrease the level of 

protection from 10,000 ppm to 5,000 

ppm. Neither impression is true. This 

rule maintains the 10,000 ppm standard 

that has been in place since 1988. The 

BLM still believes that a 10,000 ppm 

threshold is appropriate because it is 

consistent with the threshold used as 

part of the definition of ‘‘underground 

sources of drinking water’’ in EPA 

regulations implementing the Safe 

Drinking Water Act (SDWA). The 

SDWA was enacted in 1974 and is the 

primary Federal law that ensures the 

quality of American’s drinking water 

(www.epa.gov/lawsregs/rulesres/sdwa/). 

Specific comments that were based on 

the erroneous assumption that the BLM 

was changing the TDS threshold for 

usable water are summarized as follows. 

No changes to the final rule were made 

as a result of these comments. 

• Numerous comments expressed 

concern that the requirement to protect 

usable water (section 3162.5–2) as 

defined would result in significantly 

increased costs because protecting water 

with TDS levels up to 10,000 ppm 

would require running casing and 

cement much deeper than it is currently 

run. Because the definition of usable 

water has not substantially changed in 

this rule, there will be no significant 

changes in costs of running casing and 

cement. 

• Many commenters thought that 

there was no use in protecting water 

zones with TDS levels greater than 

5,000 ppm, because water with a TDS 

higher than 5,000 is not suitable for 

human, agricultural, or industrial uses. 

One comment stated that the BLM 

considers water with TDS levels greater 

than 5,000 ppm as hazardous to 

wildlife. This rule does not change the 

primary criteria for protecting usable 

water up to 10,000 ppm, which has been 

in place for the past 26 years. Given the 

increasing water scarcity and 

technological improvements in water 

treatment equipment, it is not 

unreasonable to assume aquifers with 

TDS levels above 5,000 ppm are usable 

now or will be usable in the future. 

• Some commenters expressed a 

concern that the conflicting definitions 

in Onshore Order 2 and in this rule will 

cause confusion for operators. There is 

no conflict between the definition in 

this rule and the definition in Onshore 

Order 2. This rule clarifies the term and 

incorporates specific inclusions and 

exclusion as to what is deemed to be 

usable water. 

Several comments stated that the cost 

of running surface casing and cement 

deep enough to protect all usable water 

zones, as defined, would significantly 

increase the cost of drilling wells. This 

is an erroneous concern. It is not 

uncommon for deeper usable water 

zones to be protected with intermediate 

or production casing, which is allowed 

under Onshore Order 2 and this rule. No 

changes to the final rule were made as 

a result of these comments. 

Several commenters suggested 

changing the definition of usable water 

to exclude aquifers that are not 

economical or feasible to use. The 

commenters said that these would 

include aquifers that are too deep, too 

small, too remote, or are not capable of 

achieving some set flow rate. No 

changes to the rule were made as a 

result of these comments. From a 

practical standpoint, excluding aquifers 

based on depth, size, location, flow rate, 

or other characteristics would be 

difficult in a national rule for several 

reasons. For example, the depths to 

which a water user might drill would 

depend on such factors as the need for 

water, the availability of other supplies, 

and the hydrologic characteristics of the 

aquifer (natural pressures might raise 

water in a deep well closer to the 

surface). Excluding aquifers from 

protection based on some arbitrary flow 

rate would be impractical. Measuring 

the flow rate potential of an aquifer 

would be a time-consuming and 

expensive process for operators to 

perform and for the BLM to review. Just 

as with oil and gas wells, the flow rate 

potential of a water well can depend on 

the specific location, depth, and 

methodology used. Furthermore, a flow 

rate that is inadequate for one type of 

use might be adequate for another type 

of use. State and tribal agencies, and 

EPA under the SDWA, have the 

expertise and authority to consider all 

the factors in characterizing 

groundwater. 

Several commenters questioned the 

basis for the 10,000 ppm of TDS in the 

definition. The 10,000 ppm of TDS used 

in Onshore Order 2 and this rule is 

based on part of the definition of 

‘‘underground source of drinking water’’ 

in EPA’s regulations implementing 

SDWA. 

Another change made to this 

definition in response to comments 

involved three exemptions from the 

definition of usable water listed in the 

supplemental proposed rule. The 

proposed exclusions in paragraphs 

(2)(i), (2)(ii), and (2)(iii) of the definition 

have been modified for clarity and to 

better reflect the roles of EPA and states 

and tribes in managing groundwater 

resources. 

The proposed exclusion in paragraph 

(A) of the definition, regarding 

hydrocarbon zones, was added to the 

supplemental proposed rule based on 

comments received on the initial 

proposal (77 FR 27691). Some 

commenters noted correctly that 

developing minerals from a zone that is 

also a USDW requires specific 

authorization under the SDWA. The 

BLM has edited the exclusion in former 

paragraph (A) 5 to clarify that the zone 

which the BLM approves for hydraulic 

fracturing is not considered to be usable 

water only if the operator has obtained 

all necessary authorizations from the 

EPA, the state (for public lands), or the 

tribe (for Indian lands), as appropriate, 

for mineral development in a USDW 

area. 

The BLM received several comments 

objecting to any exemptions for 

protecting aquifers, as proposed in the 

definition of ‘‘usable water’’ under 

3160.0–5. The commenters stated that it 

is impossible to predict what will 

constitute ‘‘usable’’ water in the future, 

especially considering drought and 

water scarcity. Therefore, they said that 

the BLM should be very conservative in 

protecting all groundwater with a TDS 

of less than 10,000 ppm. The 

commenters recommended deleting the 

exemptions under paragraphs (A), (B), 

and (C) of the usable water definition. 

The BLM disagrees that all groundwater 

with a TDS of less than 10,000 ppm 

must be deemed usable water in this 

final rule. The TDS is only one 

parameter in deciding whether water is 

usable. The amounts of other types of 

contaminants, depth, and available 

alternatives are other considerations. 

The final rule has modified the 

exemptions in paragraphs (2)(i), (2)(ii), 

and (2)(iii) of the usable water definition 

to clarify the central roles of states, 

tribes, and the EPA in categorizing 

groundwater and deciding upon the 

proper level of protection from 

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hydraulic fracturing operations. Those 

agencies have the expertise and 

authority to consider all local factors 

and to manage groundwater resources. 

Some of the commenters suggested 

that the BLM should incorporate the 

exemption provisions of the SDWA 

directly into the definition of usable 

water instead of relying on designations 

through the SDWA. 

No changes to this provision were 

made as a result of these comments. The 

BLM has neither the authority nor 

jurisdiction to designate groundwater as 

exempt from protection under the 

SDWA. Furthermore, the final rule 

protects usable water, which includes, 

but is not limited to USDWs. Aquifers 

that are not USDWs might be usable for 

agricultural or industrial purposes, or to 

support ecosystems, and the rule defers 

to the determinations of states (on 

Federal lands) and tribes (on Indian 

lands) as to whether such zones must be 

protected. 

One industry group seemed to favor 

requiring operators to determine the 

TDS levels of aquifers already deemed 

by the state or tribe to require 

protection, and said that the TDS 

criterion was arbitrary and capricious, 

but included the same criterion in its 

proposed definition. That group’s 

argument against the TDS criterion was 

that it did not consider other 

constituents, such as hydrocarbons, 

heavy metals, microorganisms, or toxic 

compounds, which would make waters 

unsuitable for use. The BLM’s definition 

of usable water has for many years used 

a TDS criterion and TDS is a widely 

recognized criterion for entities 

contemplating use of particular waters. 

In the United States, most users prefer 

waters containing 10,000 ppm TDS or 

less. 

The BLM agrees that different water 

users would also be concerned about 

various other water quality criteria. The 

most common dissolved solids in most 

aquifers encountered by oil and gas 

operations on Federal or Indian lands 

are salts. Operators can estimate salinity 

levels from drill logs. Other means of 

measuring TDS are straight forward and 

economical. The BLM declines to 

require operators to test aquifers for 

hydrocarbons, heavy metals, 

microorganisms or toxic compounds. 

A few commenters mentioned that 

paragraphs (1) and (3) in the definition 

in the supplemental proposed rule are 

irrelevant because they would not occur 

with TDS levels above 10,000 ppm 

anyway. Paragraph (1) includes in the 

definition of usable water all 

groundwater that meets the definition of 

USDWs in EPA’s regulations. However, 

the 10,000 ppm of TDS threshold 

established in the first sentence of the 

definition is based on part of EPA’s 

regulatory definition of ‘‘underground 

source of drinking water’’ under the 

SDWA. The commenter concludes, 

therefore, that paragraph (1) is 

redundant and unnecessary. Paragraph 

(3) includes zones designated for 

protection by a state or a tribe. 

According to the commenters, however, 

there are no states or tribes that have 

designated a TDS threshold higher than 

10,000 ppm. While the commenters are 

correct in their assertions, the BLM 

must anticipate that, in the future, 

conditions may change. Given the 

increasing threat of water scarcity and 

the advancement of technology, it is 

foreseeable that a TDS threshold higher 

than 10,000 ppm may be established 

under applicable law in the future for 

aquifers supplying agricultural, 

industrial, or ecosystem needs. By 

including these paragraphs in this rule, 

such zones would automatically be 

protected from contamination by 

subsequent hydraulic fracturing without 

requiring a rule change. No changes to 

the rule were made as a result of this 

comment. 

Several commenters stated that the 

BLM has no jurisdiction over the waters 

of the various states. States and tribes 

generally administer and regulate rights 

to use surface water and groundwater 

within their jurisdictional boundaries. 

The EPA has authority over USWD in 

relation to injection wells under the 

SDWA, although EPA can and does 

approve states and tribes to implement 

their programs in lieu of the Federal 

program. The BLM understands the 

importance of states and tribes 

regulating the use of groundwater 

within their jurisdictions and generally 

agrees with the commenters. However, 

the Mineral Leasing Act (30 U.S.C. 181, 

et seq.) gives the BLM the authority to 

lease oil and gas resources and to 

regulate the development of those 

leases. The Indian mineral statutes 

require the Secretary to regulate oil and 

gas drilling on Indian trust and 

restricted lands. This authority extends 

to the drilling of wells and to 

subsequent operations on those leases. 

Of primary importance when drilling or 

hydraulic fracturing a well is the 

protection of groundwater. The BLM 

agrees that regulation of groundwater 

quality is not within the BLM’s 

authority; however, the protection of 

those water zones during well drilling 

and hydraulic fracturing is a key 

component of the BLM’s jurisdiction 

and responsibility. No changes to the 

rule were made as a result of these 

comments. 

The BLM received comments both 

supporting and objecting to paragraph 

(2) of the definition in the supplemental 

proposed rule, which included in the 

definition of usable water, zones in use 

for supplying water for agricultural or 

industrial purposes, regardless of TDS 

concentration, unless the operator could 

demonstrate that zone would not be 

adversely affected. The commenters 

objecting to this provision said that 

operators are not in a position to know 

whether aquifers are in actual use, or to 

prove that hydraulic fracturing 

operations would not harm the water 

user, and that BLM should not be 

making determinations about 

groundwater use or harm to users. The 

BLM agrees with those comments and 

removed paragraph (2) in the final rule 

as a result. 

Commenters supporting paragraph (2) 

of the definition in the supplemental 

rule indicated that even if a zone is not 

required to be protected according to the 

definition of usable water, because that 

zone supplies water that is actually 

being used for agricultural or industrial 

purposes, the zone is self-evidently 

‘‘usable.’’ The BLM agrees that an 

aquifer could be in actual use, even if 

it exceeds 10,000 ppm TDS. However, 

the rule defers to the state or tribal 

agency to make such determinations, as 

appropriate. Entities using water 

exceeding 10,000 ppm TDS may ask the 

appropriate state or tribal agency to 

designate that zone as usable water, in 

which case it would have to be isolated 

and protected from contamination 

during hydraulic fracturing. 

One comment suggested that the 

BLM—not the operator—should make 

the determination that hydraulic 

fracturing would not harm aquifers in 

use, in paragraph (2) of the definition. 

The BLM did not make any changes to 

the rule based on this comment because 

proposed paragraph (2) has been deleted 

from the final rule based on other 

comments received. 

The final rule includes a new 

paragraph (1)(ii) that includes in the 

definition of usable water 

‘‘[u]nderground sources of drinking 

water under the law of the state (for 

Federal lands) or tribe (for Indian 

lands).’’ New paragraph (1)(ii) defers to 

designations of aquifers as sources of 

drinking by states and tribes, even if the 

aquifer would not meet the definition of 

USDW in EPA’s regulations. That could 

occur, for example, if an aquifer cannot 

supply a public water system, but is 

used for drinking water by persons not 

connected to a public water system. 

Several commenters found the 

definition of usable water in the 

supplemental proposed rule to be 

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6The EPA uses a TDS measurement of mg/l while 

the BLM uses ppm. While there is a slight 

difference in the measurements, for practical 

purposes they would yield very similar results. 

confusing because of the way it was 

organized. The BLM agrees with this 

comment and has substantially revised 

the definition. 

Several comments stated that the BLM 

should eliminate the usable water 

exemption for zones that states or tribes 

have designated as exempt (paragraph 

(4)(C) of the definition of usable water 

in the supplemental proposed rule). The 

issue raised by the commenters is that 

states and tribes typically base their 

exemptions on water that is unsuitable 

for drinking, livestock, or irrigation, and 

not on groundwater-dependent 

ecosystems. According to the comments, 

by adopting state or tribal designations, 

such aquifers would not have to be 

protected or isolated during hydraulic 

fracturing operations and this could 

damage or destroy the ecosystems that 

are dependent on them. 

The BLM did not make any changes 

to the rule based on these comments for 

two reasons. First, while the BLM is 

responsible for preventing unnecessary 

or undue degradation of resources on 

public lands and exercising part of the 

Secretary’s trust responsibility for 

Indian resources, designating the uses of 

aquifers is a matter for states and tribes, 

to the extent not otherwise inconsistent 

with the SDWA. 

Second, the BLM does not agree with 

the commenter’s assertion from a 

practical standpoint. The majority of 

groundwater-dependent ecosystems 

would be dependent on relatively 

shallow groundwater. Shallow 

groundwater (typically less than 1000 

feet deep) is protected by surface casing, 

regardless. Some commenters said that 

the criterion of 10,000 ppm TDS 

exceeds the recommended standard for 

USDW. The EPA’s definition is as 

follows: Underground source of 

drinking water (USDW) means an 

aquifer or its portion ‘‘(a)(1) Which 

supplies any public water system; or (2) 

Which contains a sufficient quantity of 

ground water to supply a public water 

system; and (i) Currently supplies 

drinking water for human consumption; 

or (ii) Contains fewer than 10,000 mg/ 

l total dissolved solids; and (b) Which 

is not an exempted aquifer’’ (40 CFR 

144.3).6

The rule seeks to protect usable water, 

which includes, but is not limited to, 

USDWs. In addition to public water 

supplies, there are many industrial and 

agricultural applications that can use 

water of up to or more than 10,000 ppm 

TDS. The final rule is not revised as a 

result of these comments. 

Some commenters suggested that the 

10,000 ppm TDS criterion could conflict 

with existing state groundwater 

standards. However, no commenter has 

explained how a requirement for oil and 

gas wells on Federal or Indian lands to 

verify isolation and protection of 

aquifers with up to 10,000 ppm TDS 

will preempt or interfere with states’ or 

tribes’ regulation of their ground water 

quality or quantity. If a state or tribe 

requires aquifers of lower quality to be 

isolated and protected, operators would 

need to comply with those 

requirements. 

Several commenters offered their own 

definitions of usable water. One 

suggestion was to incorporate the entire 

EPA definition of a USDW instead of 

developing the BLM’s own definition. 

The commenters stated that this would 

improve consistency and foster 

cooperation between the EPA and the 

BLM. The final rule references USDWs 

as one of the criteria that would 

constitute usable water. However, 

USDWs do not necessarily include 

water zones that have been designated 

by states or tribes as usable water for 

agriculture, industry, or other needs. 

The BLM believes that these zones are 

also worthy of protection. Therefore, the 

BLM did not accept this suggestion. 

Other suggestions recommended 

defining usable water as only USDWs or 

zones designated by states or tribes. In 

the final rule, the BLM adopted this 

suggestion in part by eliminating 

paragraph (2) of the definition in the 

supplemental proposed rule, which 

would have also included zones being 

used for agricultural or industrial 

purposes, regardless of the TDS level. 

One commenter stated that the BLM 

should require that casing used to 

isolate usable water be set at least 100 

feet below the base of usable water to 

ensure the usable water zone is 

protected. Another commenter 

recommended that corrosive zones and 

flow zones also be isolated. The BLM 

did not make any changes to the rule 

based on this comment because the 

scope of this rule is hydraulic 

fracturing. Well drilling, including 

requirements for casing strings and zone 

isolation, is regulated by Onshore Order 

2 and is based on site-specific downhole 

conditions. 

One commenter recommended that 

the rule refer to ‘‘established’’ usable 

water zones to add clarity. The BLM did 

not make any changes to the rule based 

on this comment because the term 

‘‘usable water’’ is clearly defined. 

Hydraulic Fracturing 

Numerous comments objected to the 

narrow focus of the definition of 

hydraulic fracturing and suggested that 

the BLM reinstate the broader definition 

from the May 2012 proposed rule. Some 

of the commenters stated that this rule 

needs to regulate well stimulation and 

acidization because these operations 

pose risks similar to those from 

hydraulic fracturing and because the 

existing regulations are inadequate to 

address these risks. The BLM did not 

revise the rule based on these 

comments. This rule specifically 

addresses risks posed by the 

combination of high pressures, chemical 

constituents, and procedures used to 

hydraulically fracture a well. Some 

commenters said that ‘‘deep hydraulic 

fracturing’’ should be exempt from this 

rule. The definition of hydraulic 

fracturing includes all hydraulic 

fracturing operations regardless of 

depth. The BLM requires protection and 

isolation of usable water regardless of 

depth of the well or depth at which 

hydraulic fracturing occurs. No changes 

to the rule were made as a result of 

these comments. 

Several commenters said that the rule 

should be modified to redefine 

hydraulic fracturing. Commenters 

indicated that the definition should 

include a statement regarding applying 

fluids under pressure. The BLM agrees 

and has revised the rule as a result of 

these comments. The BLM believes that 

an integral part of hydraulic fracturing 

is the concept of the application of high 

pressure, and this position is confirmed 

by a review of technical literature on 

hydraulic fracturing as well as 

consultation with state regulatory 

agencies. The definition in the final rule 

has been modified accordingly. 

Refracturing 

Several commenters suggested that 

the definition of refracturing should be 

modified to exempt different stages of a 

multi-stage fracturing operation. The 

commenters were concerned that under 

the definition in the supplemental 

proposed rule, the BLM could consider 

each stage as a refracture operation, 

thereby requiring a separate permit. It is 

not the intent of the BLM to require a 

separate permit for each stage of a multistage hydraulic fracturing operation and 

final section 3162.3–3(i) is modified to 

reflect that a hydraulic fracturing 

operation is considered to be complete 

only after the last stage is completed. 

The BLM did not make modifications to 

the definition of refracturing as a result 

of these comments because the 

definition of refracturing was deleted in 

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the final rule for other reasons discussed 

in other sections of the preamble. 

Several commenters suggested that 

the rule should be modified to treat 

refracturing differently than fracturing. 

The BLM disagrees with these 

comments because there is no practical 

purpose in distinguishing ‘‘fracturing’’ 

from ‘‘refracturing.’’ The permitting, 

operational issues, mechanical integrity 

test requirements, wellbore integrity, 

disclosure and possible variances for 

newly drilled wells and older 

previously fractured wells are the same; 

therefore, the BLM has removed the 

term and definition of refracturing in 

the final rule. The primary purpose of 

differentiating the two in the proposed 

rule was to recognize that the 

information required in section 3162.3– 

3(e) of the rule may not be available for 

older wells that would be ‘‘refractured.’’ 

However, upon further deliberation, the 

BLM determined that would be case for 

any well where approval for hydraulic 

fracturing was given subsequent to the 

drilling and completion of the well, 

regardless of whether or not the well 

had been hydraulically fractured 

previously. Therefore, the definition of 

refracturing is deleted from the final 

rule and all references to the term are 

removed. The requirements for 

hydraulic fracturing now apply 

uniformly to all fracturing operations 

that meet the definition in the rule. 

Section 3162.3–3(a) in the final rule was 

modified to allow for cases where 

hydraulic fracturing is approved 

subsequent to the drilling and 

completion of a well. 

Several comments recommended that 

any hydraulic fracturing done within a 

certain amount of time of a previous 

fracturing job or that is done under 

similar conditions as the original 

hydraulic fracturing, should not be 

considered refracturing. The BLM did 

not make any changes based on this 

comment because the term 

‘‘refracturing’’ was deleted from the 

final rule. This rule applies whenever 

pressure is used to fracture reservoir 

rock, regardless of how or when the 

operation occurs relative to a previous 

hydraulic fracturing. 

One comment recommended 

specifically excluding ‘‘enhanced oil 

recovery using carbon dioxide’’ from the 

scope of this rule. However, if carbon 

dioxide or any other gas is used under 

pressure to fracture reservoir rock, the 

operation poses much the same risk as 

if the fracturing was done using a liquid 

as the fracturing fluid. The term ‘‘fluid’’ 

in the definition of hydraulic fracturing 

includes both liquids and gases. 

However, if the carbon dioxide or other 

fluid is injected not to fracture reservoir 

rock, but to stimulate production by 

other means, it would not be a hydraulic 

fracturing operation. 

What constitutes ‘‘completion?’’ 

Several commenters said that the rule 

should be modified to define what 

constitutes the completion of hydraulic 

fracturing operations. The commenters 

indicated that the supplemental 

proposed rule would require the 

submittal of a completion report within 

30 days of completion of hydraulic 

fracturing operations. The BLM did not 

revise the rule as a result of these 

comments. The BLM does not believe 

that a definition of ‘‘completion’’ is 

warranted in the context of these 

regulations. By definition, hydraulic 

fracturing ends when pressure is 

released for the last stage of the 

operation. It is at this point that the 30- 

day timeframe would begin for each 

well that is hydraulically fractured. 

CEL Definition 

Several commenters said that the term 

‘‘micro-seismograms’’ should be 

dropped from the list of CEL tools 

discussed in supplemental section 

3163–3(e)(2). Commenters indicated 

that the term ‘‘micro-seismogram’’ as 

currently used does not refer to 

evaluating cement quality and is 

therefore confusing when included in 

cement evaluation provisions. The 

commenters said that conventional 

cement bond logs (CBL) used for the 

purposes of evaluating cement integrity 

around casing can be displayed by a 

variety of methods. One of those 

techniques was termed ‘‘microseismogram’’ (MSG) and referred to the 

x-y presentation of the entire received 

signal. Another presentation method, 

the variable density log (VDL), only 

displays the amplitude of that signal. 

Either, or both, of these presentation 

methods can be used to evaluate the 

integrity of the cement bond to casing 

and formation. It is true that the term 

‘‘micro-seismogram’’ has much broader 

implications than just cement 

evaluation, and the rule has been 

modified as a result of these comments. 

The CEL discussion has been removed 

from the regulatory text at proposed 

section 3162.3–3(e)(2) and placed as a 

unique definition in the final rule in 

section 3160.0–5. Further, the CEL 

definition has been revised to remove 

any references to ‘‘micro-seismograms.’’ 

The BLM believes that this clarifies the 

intent of the rule. Additionally, section 

3162.3–3(e)(2)(i) has been revised to 

provide flexibility for the authorized 

officer to approve other appropriate 

cement evaluation methods or devices. 

Type Well 

Numerous commenters suggested that 

limiting the multiple well permitting, or 

type well, availability (referred to as 

Master Hydraulic Fracturing Plan in this 

rule) to a ‘‘field’’ in the definition was 

too restrictive and would nullify most of 

the benefits of a group submittal. Some 

commenters recommended that the 

BLM should better define what is meant 

by a ‘‘field’’. Commenters offered 

numerous suggestions on the extent of 

what an MHFP should cover including 

‘‘basin,’’ ‘‘pool,’’ ‘‘area,’’ ‘‘resource 

play,’’ ‘‘geographic area,’’ ‘‘geologic 

formation,’’ ‘‘section,’’ ‘‘unitized area,’’ 

and ‘‘county.’’ The BLM agrees that the 

term ‘‘field’’ is potentially too limiting, 

and has deleted the requirement that 

wells included in the scope of an MHFP 

must be in the same field. However, the 

BLM disagrees that other terms such as 

those suggested would be preferable. 

Therefore, in the final rule, the criteria 

for the scope of an MHFP are wells that 

are geologically similar. Under this rule, 

the decision on the geographic or 

geologic extent of an MHFP is up to the 

field office reviewing the application 

and is based on local geology and 

drilling practices. 

Several commenters asked if there 

would be any limits on the number of 

wells or the timeframe over which a 

multiple well permit could apply to 

other wells in a group submission for 

hydraulic fracturing. Under the final 

rule, the MHFP applies to any number 

of wells that meet the criteria in the 

definition of an MHFP and there is no 

specific timeframe for when wells under 

an MHFP must be drilled. Decisions 

regarding the applicability of wells 

under an MHFP are made at the BLM 

field office based on local geologic 

conditions and drilling practices. 

Several commenters suggested two 

definitions of type well: One that would 

apply to permitting and one that would 

apply to operations such as running a 

CEL. The BLM did not revise the rule 

based on these comments because the 

term ‘‘type well’’ is deleted in the final 

rule. While the option of permitting a 

group of wells to be hydraulically 

fractured is retained in the final rule 

(now called an MHFP), the requirement 

to run a CEL on a type well is deleted 

and replaced with new requirements 

that will help to ensure adequate 

cementing and protection of aquifers 

(see final section 3162.3–3(e)). 

The BLM received several comments 

stating that to be considered a type well, 

the operator must demonstrate 

successful replication of operations. No 

changes to the rule were made as a 

result of this comment because type 

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wells are deleted in the final rule. For 

group submittals under an MHFP, the 

BLM field offices have the discretion to 

require individual permitting of wells if 

the operator is unable to successfully 

replicate the operations described in an 

MHFP. 

Section 3162.3–2 Subsequent Well 

Operations 

Revised sections 3162.3–2(a) and (b) 

no longer contain reference to 

nonroutine or routine fracturing jobs. 

All other injection activities must still 

comply with section 3162.3–2, while 

hydraulic fracturing operations must 

comply with the requirements under 

revised section 3162.3–3. 

Section 3162.3–3(a) Scope 

Section 3162.3–3 lists the 

requirements concerning all hydraulic 

fracturing operations and paragraph (a) 

of this section establishes the conditions 

under which some wells may be 

exempted from certain requirements (or 

‘‘grandfathered’’ in) as a way to 

transition from the previous regulations 

to these regulations. 

The BLM made several changes to 

paragraph (a) of the final rule. The term 

‘‘refracturing’’ is removed from the 

activities to which this section applies, 

because the term ‘‘refracturing,’’ and all 

references to it are deleted in the final 

rule. 

In addition, a table is added to this 

section to clarify how the rule will be 

implemented with regard to wells in 

various stages of permitting, drilling, 

and completion. In general, any well 

that is drilled after June 24, 2015, or that 

was drilled more than 6 months before 

June 24, 2015 must comply with all 

parts of this rule, including the 

permitting, cementing, mechanical 

integrity testing, monitoring, handling 

and storage of recovered fluid, and 

reporting requirements. However, in 

order to reduce the economic and 

workload impacts of implementing this 

rule, there are three categories in which 

an operator can hydraulically fracture a 

well without submitting a new APD or 

NOI under sections 3162.3–3(c) and (d). 

If an operator has an APD approved 

within the 2 years immediately prior to 

June 24, 2015, but has not commenced 

drilling operations, or has commenced 

drilling prior to June 24, 2015, but has 

not completed those operations, or has 

completed drilling operations within 

the 6 months immediately prior to June 

24, 2015, and commences hydraulic 

fracturing operations within 90 days 

after June 24, 2015, the operator does 

not need to submit a new APD or NOI, 

or await the approval of the BLM before 

commencing hydraulic fracturing 

operations. The operator will need to 

comply with the provisions of 

paragraphs (b), (e), (f), (g), (h), (i), and 

(j) of the rule. 

Those provisions are added to 

paragraph (a) to reduce costs and 

scheduling conflicts that could arise 

otherwise, while still ensuring safe and 

responsible hydraulic fracturing 

operations. Operators typically schedule 

hydraulic fracturing services 6 months 

in advance, though the requirements of 

every market are different. The BLM 

determined that the 90 days between 

publication of this the final rule and its 

effective date, plus an additional 90 

days provided in paragraph (a) will be 

adequate to accommodate most 

potential scheduling conflicts. If the 

operator wishes to conduct hydraulic 

fracturing more than 90 days after June 

24, 2015, under each of these three 

scenarios, however, the operator must 

comply with all of the paragraphs in 

this section, including submission of an 

application and obtaining approval from 

BLM to conduct hydraulic fracturing 

operations. 

The final category in the table in 

paragraph (a) is wells for which drilling 

operations are completed prior to the 

effective date of the rule and hydraulic 

fracturing operations are conducted 

more than 6 months after the effective 

date of the rule. Operators would need 

to obtain the BLM’s approval to conduct 

hydraulic fracturing operations, but not 

all operators would have the cementing 

verification records that are required for 

new wells. Rather than prohibit 

hydraulic fracturing of wells for lack of 

documentation not required at the time 

of construction, the rule provides in 

section 3162.3–3(e)(1)(ii) that operators 

must provide the relevant 

documentation that is available, and 

that the BLM may require additional 

testing or verifications on a case-by-case 

basis. For any existing well, an operator 

may request approval to conduct 

hydraulic fracturing operations by 

submitting an NOI under paragraph 

(c)(2) of the final rule. 

Several commenters stated that the 

rule should be modified to further 

clarify the scope of this rule as it relates 

to injection activities. The commenters 

indicated that the provisions at this 

section cloud whether or not the 

majority of this rule applies to other 

injection or disposal operations. The 

BLM has revised the rule as a result of 

these comments. Injection activities 

have been removed from this section to 

avoid any confusion because injection is 

specifically addressed by existing 

section 3162.3–2. The BLM believes this 

change provides the necessary clarity 

regarding scope. 

Section 3162.3–3(b) Isolation of Usable 

Water 

The only change made to this section 

of the final rule is the deletion of the 

term ‘‘refracturing’’ because it, and all 

references to it, are removed from the 

rule. The BLM received no substantive 

comments on this section. 

Section 3162.3–3(c) How To Apply for 

Hydraulic Fracturing Approval 

This section requires an operator to 

submit a proposal for hydraulic 

fracturing to the BLM for approval. The 

operator may submit an application for 

a single well or for a group of wells 

under an MHFP. Prior to this rule, the 

regulations only required an NOI for 

‘‘non-routine’’ hydraulic fracturing 

operations. The application requirement 

in the final rule is a new process. The 

request for approval of hydraulic 

fracturing may be submitted with either 

an APD or as an NOI. 

Numerous changes were made to this 

section in the final rule. The description 

of how to apply for the hydraulic 

fracturing of multiple wells is moved 

from section (d) of the supplemental 

proposed rule to section (c)(3) of the 

final rule because it has more to do with 

the permitting process than the 

information that an operator must 

submit to the BLM. This section also 

references an MHFP instead of a type 

well, as proposed in the supplemental 

proposed rule. A discussion of the 

MHFP is given in the definitions section 

of the preamble. 

The final rule revises some of the 

conditions under which an operator 

would have to resubmit a request for 

approval to hydraulically fracture a 

well. In the supplemental proposed rule 

(section 3162.3–3(c)(3)(i)), an operator 

would not have had to get approval to 

refracture a well if the refracturing was 

done within 5 years of the original 

fracturing approval. The premise of this 

requirement was that an MIT, required 

prior to fracturing under section 3162.3– 

3(f) of this rule, is typically valid for a 

period of 5 years in some state 

regulations (e.g., Colorado, Montana, 

and Wyoming) for MITs. The BLM 

originally believed that because an MIT 

was required prior to the original 

hydraulic fracturing operation, it would 

not be necessary to re-run the MIT for 

a period of 5 years after that. However, 

upon further examination, the BLM 

determined that the 5-year timeframe for 

MITs in these state regulations is for the 

purpose of ensuring wellbore integrity 

for injection wells under the UIC 

program and has little relevance to 

hydraulic fracturing. 

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The BLM now believes that an MIT 

should be required prior to any 

hydraulic fracturing operation because 

of the high pressures and wellbore 

configurations used (such as a fracturing 

string) during hydraulic fracturing 

operations. Therefore, the final rule is 

revised to require approval and 

compliance with all sections of this rule 

for all fracturing operations, whether the 

well is being refractured or fractured for 

the first time (some hydraulic fracturing 

operations may not have to comply with 

sections (c), (d), or (e)—see the table in 

section (a)). 

The supplemental proposed rule 

(section 3162.3–3(c)(3)(i)) would also 

have required the operator to resubmit 

an NOI for hydraulic fracturing if 

fracturing had not commenced within 5 

years of the original approval. This 

requirement is deleted in the final rule 

because the BLM determined that as 

long as the proposal for hydraulic 

fracturing had not changed and there 

was no new information regarding the 

geology or potential impacts, the 5-year 

time frame was unnecessary. If the 

operator has significant new 

information about the geology of the 

area, the stimulation operation or 

technology to be used or potential 

impacts, it must submit a new NOI. 

The final rule also eliminates 

paragraph (c)(3)(iii) in the supplemental 

proposed rule because it dealt with 

refracturing, a term that is deleted in the 

final rule along with all references to it. 

Some commenters requested that the 

BLM eliminate the requirement for prior 

approval of hydraulic fracturing 

operations, suggesting that it would be 

unnecessary and costly. As stated in the 

background section of this rule, the 

BLM believes this rule is necessary, and 

prior approval is an essential part of this 

rule. The information included in the 

application allows the BLM to evaluate 

the proposal and to assess the potential 

impacts of the proposal. Prior approval 

allows the BLM to mitigate potential 

impacts through modification of the 

proposal or by attaching conditions of 

approval, after compliance with other 

statutes, such as NEPA. 

Several commenters expressed 

concern that many of the items 

requested in the application, such as 

estimated total volume of fluid to be 

used and anticipated surface treating 

pressure range, are not known at the 

time the application is submitted. The 

BLM recognizes that exact volumes and 

pressures will not be known at the time 

the application is submitted, and the 

provisions at final section 3162.3–3(d) 

allow flexibility by requiring estimated 

or anticipated values. The items are 

necessary to allow the BLM to assess the 

proposal and ensure adequate storage 

for the fluids and proper casing strength 

to withstand the anticipated pressures. 

Another commenter suggested 

eliminating some of the requirements 

needed for approval because Onshore 

Oil and Gas Order No. 1, Oil and Gas 

Operations; Federal and Indian Oil and 

Gas Leases; Approval of Operations (72 

FR 10308) (Onshore Order 1), section III. 

D. 3, already requires them, and they are 

included with the APD. As stated in 

final section 3162.3–3(c)(1), the operator 

may submit the information required in 

paragraph (d) of this section with its 

APD. If the information is already 

included in the APD, it would not need 

to be repeated. Another commenter 

recommended eliminating some of the 

requirements in the application, since 

those items will be included in the 

subsequent report of operations. The 

information in the application is 

necessary for the BLM to assess the 

potential impacts of the proposed 

operation; additionally, some of the 

information requested in the application 

is identified as proposed or estimated. 

The information required in the Sundry 

Notice and Report on Wells (Form 

3160–5) as a subsequent report 

(‘‘subsequent report’’) is the actual data 

from the completed hydraulic fracturing 

operations. No revisions to the rule were 

made as a result of these comments. 

One commenter suggested that the 

BLM should allow a ‘‘type frack’’ 

approval instead of a type well 

approval. While the BLM is unclear 

what the commenter is specifically 

referring to, the BLM assumes that the 

commenter means that the hydraulic 

fracturing operation itself be approved 

for a group of wells. The BLM believes 

that the final rule’s MHFP submission 

addresses this comment. The MHFP will 

allow an operator to describe a generic 

hydraulic fracturing process for a group 

of wells by providing the information 

required in section 3162.3–3(d) for those 

wells. No changes to the rule were made 

as a result of this comment. 

Numerous commenters objected to 

permitting hydraulic fracturing for a 

group of wells. Some of the commenters 

stated that geologic conditions are too 

variable to allow any kind of group 

permitting while other commenters 

stated that the extent of the grouping 

should be explicitly defined and that 

strict limitations should be placed on 

the maximum allowable extent of an 

MHFP. The BLM disagrees with these 

comments because rigid, detailed 

criteria for what can be considered in an 

MHFP is not practical in a national rule 

of general applicability. The local field 

office must have some flexibility to 

define the extent of an MHFP based on 

local geology, drilling practices, and 

other applicable criteria. No revisions to 

the rule were made as a result of this 

comment. The benefits of an MHFP are 

that it allows the BLM to frontload its 

analysis of proposed hydraulic 

fracturing operations in a given area 

where the geologic characteristics for 

each well are substantially similar. It 

also provides early notice to the public 

of where such operations are being 

contemplated, and of the scale or 

intensity of the development. This 

frontloaded analysis provides the BLM 

with the tools necessary to perform a 

more comprehensive and streamlined 

review of hydraulic fracturing 

proposals, while maintaining the 

appropriate standards that ensure 

wellbore integrity and useable water 

protection. 

Several commenters suggested that 

exploratory wells could be used as type 

wells because they were drilled 

vertically through the target formations 

and lithologic and reservoir data was 

obtained from them. Other commenters 

suggested that wells drilled by other 

operators could be used as a type well, 

while some commenters stated that type 

wells must be drilled by the same 

operator because drilling practices vary 

between operators. No revisions to the 

rule were made as a result of these 

comments because the requirement to 

drill a type well in order to receive 

approval to hydraulically fracture a 

group of wells with a single permit 

submittal is deleted in the final rule. 

The MHFP, which replaces the type 

well concept, is required to contain the 

information in sections 3162.3–3(d)(1) 

through (d)(7); however, the well 

integrity information required by 

section 3162.3–3(e) is not required to be 

included in the MHFP. Rather, the well 

integrity information required by 

section 3162.3–3(e) must now be 

submitted for each well 48 hours prior 

to commencing hydraulic fracturing. 

The MHFP only applies to wells drilled 

by the same operator. Section 3162.3– 

3(c)(3) states that ‘‘the operator may 

submit a MHFP,’’ thereby eliminating 

the possibility that an MHFP could 

apply to wells drilled by multiple 

operators. The BLM decided to restrict 

MHFPs to wells drilled by the same 

operator because doing otherwise would 

be difficult to administer and the BLM 

believes that drilling by different 

operators would only apply in rare 

instances. 

Several commenters asked that the 

BLM allow the type well concept to 

include fracture modeling. The MHFP, 

which replaces the type well concept for 

permitting, requires all information 

required in sections 3162.3–3(d)(1) 

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16148 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

through (d)(7) to be included in an 

MHFP. Final section 3162.3–3(d)(4)(iii) 

requires the operator to submit a map 

showing the estimated fracture direction 

and length. Although the final rule does 

not require fracture modeling, it would 

fulfill the requirements of this section. 

No revisions to the rule are made as a 

result of these comments because the 

rule already allows fracture estimations 

or modeling to be applied to a group of 

wells under an MHFP. 

Several commenters stated that the 

CEL for a type well should be applicable 

to wells that meet the criteria for group 

approval, but were submitted under a 

separate NOI. The BLM did not revise 

the rule as a result of these comments 

because the requirements to run CELs 

on type wells and submit the results of 

the CEL as part of the group approval 

package are eliminated in the final rule. 

Several comments suggested that for 

group hydraulic fracturing submissions, 

the operator should be required to 

certify that the cement, fracturing fluids, 

and drilling practices for all wells 

included in the submission comply with 

the information submitted in the MHFP. 

The BLM did not incorporate this 

suggestion into the final rule because a 

certification is not necessary to ensure 

compliance with the approved NOI for 

multiple wells, and because information 

related to well integrity is now required 

for each individual well. Any 

unapproved deviation from the 

approved NOI and MHFP would be 

considered a violation and would be 

enforced under existing subpart 3163, 

Noncompliance, Assessments, and 

Penalties. One comment said that the 

option to permit multiple wells will not 

help operators who do not drill wells in 

groups. In the final rule, MHFPs will 

primarily streamline the permitting 

process for operators who are hydraulic 

fracturing multiple wells within an area 

having similar geology. No revisions to 

the rule were made as a result of this 

comment. The fact that not every 

operator can take advantage of a 

provision of the rule designed to 

streamline the process does not make 

that provision undesirable or 

unnecessary. 

Section 3162.3–3(d) Application for 

Hydraulic Fracturing 

This section specifies that the 

application must include: 

• Information about the geology and 

the formation, confining zones, usable 

water (depths estimated), faults and 

fractures, location of water supply, and 

transportation method. This information 

is generally consistent with the 

requirements in Onshore Order 1; 

• Information about the proposed 

hydraulic fracturing operation, the 

volume of fluid to be used, the 

maximum anticipated surface pressure, 

wellbore trajectory, the estimated 

direction and length of fractures, and 

the locations, trajectories, and depths of 

existing wellbores within a half mile of 

the wellbore; and 

• Information about how the operator 

will handle recovered fluids, the 

estimated volume of fluids to be 

recovered, and the proposed disposal 

method. 

Operators planning to conduct 

hydraulic fracturing should already 

possess that information because 

hydraulic fracturing is a complex 

operation and would only be conducted 

pursuant to a plan for performance. 

The final rule incorporated several 

revisions to this section. Requirements 

relating to an MHFP (referred to as a 

submission for a group of wells in the 

supplemental proposed rule) are moved 

from section (d) to section (c) because 

section (c) has to do with how to apply 

for hydraulic fracturing approval. A 

discussion of the MHFP is given in the 

definitions section and the response to 

comments on the type well in the 

proposed rule are addressed in the 

discussion of section (c). 

Section 3162.3–3(d)(1) in the 

supplemental proposed rule would have 

required the operator to identify the 

geologic formation that would be 

hydraulically fractured, including 

measured depths of the top and bottom 

of the formation. The final rule requires 

that the operator identify both the 

measured depths and the true vertical 

depths of the formation to be 

hydraulically fractured (paragraph 

(d)(1)(i)). This section of the final rule 

also requires the operator to identify the 

measured and true vertical depths of the 

confining zone (paragraph (d)(1)(ii)). 

The requirement to identify usable 

water zones is moved from paragraph 

(d)(2) in the supplemental proposed rule 

to final paragraph (d)(1)(iii), along with 

a new requirement to state the measured 

and true vertical depths of the top and 

bottom of all usable water zones. The 

requirement to identify occurrences of 

usable water with a drill log in the 

supplemental proposed rule is deleted 

in the final rule. The BLM determined 

that it is not always necessary or 

practical to require a drill log to identify 

usable water and that there is no reason 

to be prescriptive about how usable 

water is identified. The BLM made these 

changes for several reasons. First, the 

BLM believes that by grouping all 

informational requirements relating to 

wellbore geometry into a single section, 

the clarity of the regulation is improved. 

Second, the BLM added a requirement 

to identify the ‘‘true vertical depth’’ of 

tops and bottoms of all the geologic 

zones in order to ascertain the vertical 

separation between zones. Also, under 

the final rule, the operator is required to 

identify the confining zone that is 

capable of preventing fluid migration 

between the zone that will be 

hydraulically fractured and any usable 

water zones. 

Section 3162.3–3(d)(2) is revised in 

the final rule to require the operator to 

submit a map showing any faults or 

fractures within one-half mile of the 

wellbore trajectory that may transect the 

confining zone. This will allow the BLM 

to identify and analyze during the 

permit review process any potential for 

hydraulic fracturing fluid to migrate 

outside of the zone being fractured. 

Section 3162.3–3(d)(3) in the 

supplemental proposed rule is separated 

in the final rule to improve clarity. This 

section in the supplemental proposed 

rule contained requirements for downhole information (e.g., depth of 

perforations, estimated pump pressures) 

as well as information on water supply 

and transportation routes. In the final 

rule, section (d)(3) is now specific to 

water supply and transportation routes; 

downhole information is moved to 

section (d)(4), which is specific to the 

technical aspects of hydraulic 

fracturing. 

Several changes are made to 

supplemental proposed rule section 

3162.3–3(d)(4) to improve clarity and to 

identify potential ‘‘frack hits.’’ ‘‘Frack 

hit’’ is a common term for a hydraulic 

fracturing operation that causes an 

unplanned surge of pressurized fluid 

into another well, often resulting in 

surface spills. The supplement rule 

required three different pressures to be 

included in the application: Estimated 

pump pressure (paragraph (d)(3) in the 

supplemental proposed rule), 

anticipated surface treating pressure 

range (paragraph (d)(4)(ii) in the 

supplemental proposed rule), and 

maximum injection treating pressure 

(paragraph (d)(4)(iii) in the 

supplemental proposed rule). In the 

final rule, those three pressures are 

replaced with a single pressure to be 

reported: The maximum anticipated 

surface pressure that will be applied 

during operations. The BLM determined 

that this was the clearest and most 

useful pressure because this will be the 

pressure at which the MIT must be run 

under section 3162.3–3(f) of the rule. 

This change is also made to eliminate 

the term ‘‘treating,’’ which may not be 

universally understood. 

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Section 3162.3–3(d)(4)(iii) in the 

supplemental proposed rule would have 

required the operator to submit the 

estimated fracture direction, length, and 

height, along with a map showing the 

estimated fracture propagation. The 

final rule adds several additional 

requirements to this section that will 

allow the BLM to determine during the 

permit review process the potential for 

‘‘frack hits.’’ In addition to the fracture 

propagation (including direction and 

length), the map must also show the 

trajectory of the wellbore into which 

hydraulic fracturing fluid will be 

injected and the trajectory of all existing 

wellbores and trajectories within onehalf mile of the wellbore that will be 

used for hydraulic fracturing. 

Additionally, the required map must 

identify the true vertical depth of each 

wellbore shown on the map. 

Section (d)(4)(v) in the supplemental 

proposed rule, requiring the estimated 

vertical distance to the nearest usable 

water aquifer above the fracture zone, is 

reworded for clarity. In the final rule, 

section (d)(4)(iv) requires the estimated 

minimum vertical distance between the 

top of the fracture zone and the nearest 

usable water zone. 

Section (d)(5) in the supplemental 

proposed rule, regarding the handling of 

recovered fluid, is reworded in the final 

rule to conform to changes made to 

section (h). The only period for which 

information on handling recovered fluid 

is necessary under the final rule is the 

period between the completion of 

hydraulic fracturing operations and the 

approval of a water disposal plan under 

Onshore Order 7. A complete discussion 

of this change is given under section (h) 

of this preamble. 

Section (d)(5)(iii) in the supplemental 

proposed rule is clarified in the final 

rule by better defining ‘‘handling’’ 

versus ‘‘disposal.’’ In the supplemental 

proposed rule, disposal included 

injection, hauling by truck, or 

transporting by pipeline. The BLM 

recognizes that hauling by truck or 

transportation by pipeline are not 

disposal methods, but transportation 

methods. In the final rule, the disposal 

options include injection, storage, and 

recycling. 

Section (d)(6) of the final rule is 

added to include additional information 

requirements if the operator requests 

approval for hydraulic fracturing in an 

NOI instead of in an APD. One of these 

requirements (section (d)(6)(i)) is a 

surface use plan of operations if the 

hydraulic fracturing operation would 

include additional surface disturbance. 

If the request was received as part of an 

APD, the surface use plan of operations 

would already be included. 

The other requirement is, by reference 

to paragraph (e), documentation that an 

adequate cement job was achieved for 

all casing strings designed to isolate 

usable water zones. 

Pre-Disclosure 

A few commenters asked that the 

volume and chemical composition of 

flowback water be disclosed in the 

permit application. Section 3162.3– 

3(d)(5)(i) of the final rule requires the 

operator to provide the estimated 

volume of fluid to be recovered in its 

application. The projected chemical 

composition of this fluid is not required. 

Providing the chemical composition of 

the recovered fluid would require 

speculation as to the chemistry of fluids 

in the target zone, and their reactions, 

if any, with the hydraulic fracturing 

fluids and therefore would be 

impractical to request, and not likely to 

be useful. The BLM has determined that 

operators often change the chemical 

composition of hydraulic fracturing 

fluids after approval of fracturing 

operations, in response to such factors 

as availability of chemicals, changes in 

vendor, and unexpected geologic 

conditions. Thus, the reliability of the 

pre-operational estimated composition 

of flowback fluids likely will not be 

known with precision at the application 

stage. It is important at the approval 

stage, however, for the operator to show 

that it has an adequate plan to manage 

and contain the recovered fluids that 

would prevent them from contaminating 

surface water or groundwater without 

regard to their specific chemical 

composition. The rule presumes that all 

recovered fluids would pose hazards to 

surface or ground water if they are not 

properly isolated. No revisions to the 

rule were made as a result of these 

comments. 

Some commenters requested that the 

BLM require up-front disclosure of the 

chemicals proposed for use in the 

hydraulic fracturing fluid and that this 

information be publicly available. 

Commenters asserted that chemicals 

must be disclosed both before and after 

well stimulation in order to achieve the 

BLM’s goals of protecting public health 

and the environment. The rule is not 

revised based on these comments. 

Analysis of the impacts from hydraulic 

fracturing is done as part of the NEPA 

analysis conducted prior to the issuance 

of permits. The exact composition of the 

fluid proposed for use is not required 

because the BLM’s goal is to ensure that 

operators contain all fluids regardless of 

their composition. All fluids are 

conservatively treated as if they are 

hazardous and need to be contained. In 

undertaking NEPA analysis to support 

the Bureau’s decision to issue a permit, 

the BLM will assume that the chemicals 

used in conducting hydraulic fracturing 

operations may be hazardous. The BLM 

believes that the post-fracturing 

disclosures and certifications of 

chemicals and additives provide 

adequate information for other 

purposes, such as to inform the 

community of the chemicals involved, 

and to assist in clean-up of any spills. 

Several commenters suggested that all 

of the information required in the 

subsequent report should be disclosed 

in the application for hydraulic 

fracturing approval. The BLM did not 

make any changes to the rule as a result 

of these comments because not all of the 

information required in the subsequent 

report is relevant or available at the time 

the operator submits the application. 

When the proposal for hydraulic 

fracturing is submitted with an APD, 

items such as well logs are not available 

because the well has not yet been 

drilled. 

The original proposed rule required 

the NOI to contain a certification signed 

by the operator that the proposed 

treatment fluid complies with all 

applicable permitting and notice 

requirements as well as all applicable 

Federal, tribal, state, and local laws, 

rules, and regulations. That requirement 

was deleted in the supplemental 

proposed rule. Some commenters 

supported eliminating this requirement 

while other commenters requested that 

the originally proposed requirement be 

reinstituted. As was stated in the 

preamble of the supplemental proposed 

rule, the BLM believes that requiring 

this certification after the operator has 

completed hydraulic fracturing 

operations (see final section 3162.3– 

3(i)(8)) adequately protects Federal and 

Indian lands and resources and, 

therefore, the burden on industry of 

providing the information and on the 

BLM of reviewing that information at 

the application stage is not justified. 

The commenters requesting the 

requirement be reinstituted stated the 

rule removes the first layer of 

accountability for industry by not even 

requiring them to say they will comply 

with permitting, and the lack of 

certification removes a tool to hold 

operators accountable to follow the 

regulations. The BLM disagrees. The 

operators are required to comply with 

all applicable laws and regulations, 

regardless of when the information is 

submitted. A certification in the NOI 

does not add any value to the permit 

and lack of a certification in the notice 

does not restrain enforcement in the 

future. Therefore, no revisions to the 

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rule are made as a result of this 

comment. 

Several comments suggested that the 

BLM allow a ‘‘master chemical plan’’ to 

be submitted for wells that are proposed 

for hydraulic fracturing in the same 

field. According to the commenter, this 

plan could be used for routine hydraulic 

fracturing operations to help streamline 

the permitting process. However, the 

BLM is not requiring chemical 

disclosure prior to hydraulic fracturing, 

so a specific ‘‘master chemical plan’’ is 

unnecessary. 

Confining Zone 

Numerous comments said that the 

rule should be modified to add a 

definition of ‘‘confining zone.’’ 

Additionally, the commenters indicated 

that the NOI required at 43 CFR 3162.3– 

3(d) should include the identification of 

an impermeable confining zone that 

would protect water sources from 

vertical migration of hydraulic 

fracturing fluids and associated brines. 

The BLM agrees with these comments. 

The final rule includes a definition of 

confining zone and a requirement that 

operators identify the measured and 

true vertical depths of the top and 

bottom of the confining zone in their 

permit application. In addition, in the 

final rule the operator must identify all 

known faults and fractures within onehalf mile of the wellbore that transect 

the confining zone. These additions will 

allow the BLM to further ensure that the 

hydraulic fracturing fluid will not 

migrate outside of the intended zone in 

order to protect usable water. 

Several comments asked that the BLM 

specify a minimum ‘‘vertical buffer’’ 

between the zone that is to be 

hydraulically fractured and the deepest 

aquifer. The BLM did not include this 

requirement in the final rule because the 

BLM must maintain the flexibility for 

field offices to review hydraulic 

fracturing applications on a case-by-case 

basis and apply site-specific conditions 

of approval. A minimum vertical 

distance that is appropriate in one area 

might be inadequate or overly restrictive 

in other areas based on the intervening 

geology. Furthermore, fracking 

technologies are likely to continue to 

improve an operator’s control over the 

propagation of fissures. 

Master Drilling Plan 

Several commenters said that the rule 

should be modified to allow operators to 

submit a field-specific casing design and 

cementing plan and subsequently 

submit verification of a successful 

cement job. The BLM did not revise the 

rule as a result of these comments. This 

comment addresses the concept of a 

Master Development Plan (MDP) that is 

already described in and provided for 

by Onshore Order 1 for newly drilled 

wells. The MDP addresses the casing 

and cementing design of all of the wells 

within that MDP. Drilling operations 

and the associated MDP process is 

outside the scope of this rulemaking. 

One commenter suggested that 

fracture modeling could be done for a 

group of wells instead of requiring a 

model for every well. The BLM did not 

revise the rule as a result of this 

comment for two reasons. First, neither 

the proposed rules nor the final rule 

require fracture modeling. Both allow 

for submittal of ‘‘estimated’’ fracture 

data. Second, fracture estimates for 

zones that are in substantially similar 

geologic regimes could be included in 

the MHFP under final section 3162.3– 

3(c). 

Use of Estimates 

One commenter expressed concern 

with the use of the term ‘‘estimate’’ in 

the supplemental proposed rule as it 

pertains to operator submissions under 

section 3162.3–3(d). The commenter 

stated that the BLM would be unable to 

ensure the protection of usable water 

zones if the operator is allowed to 

submit estimates. The BLM disagrees 

with this comment. This provision 

allows the operator to estimate some 

items, such as the depth of usable water 

and the pump pressure, in the APD and 

NOI. Allowing estimates in the APD and 

NOI instead of actual information does 

not compromise the safeguards for 

protection of usable water. At the time 

the APD and NOI is submitted, in many 

instances some of the required 

information cannot be known for 

certain, because the well has not yet 

been drilled. The estimates provide the 

BLM with sufficient information to 

evaluate the potential impacts of the 

planned operation and to ensure that 

usable water zones are adequately 

protected. No revisions to the rule are 

made as a result of this comment. 

Changes From Original Proposed Rule 

One commenter expressed concern 

that the changes made to the 

requirements in the NOI from the 

original proposed rule to the 

supplemental proposed rule do not 

seem designed to provide adequate 

safeguards for ecological and human 

resources. The BLM disagrees with this 

comment. The changes from the original 

proposed rule to the supplemental 

proposed rule were based on the 

comments received from individuals, 

Federal and state Governments, and 

agencies, interest groups, and industry 

representatives. The changes to each 

section and the rationale for the changes 

were discussed in the preamble of the 

supplemental proposed rule. One of the 

primary goals of the rule is to provide 

adequate safeguards for resources in and 

on the public lands and tribal lands, and 

thus for the persons who use those 

resources. The BLM believes the 

changes proposed in the supplemental 

proposed rule and the provisions of the 

final rule, along with existing processes 

for reviewing and approving oil and gas 

development proposals, accomplish that 

goal. 

Permitting Multiple Wells With an NOI 

The supplemental proposed rule 

would have allowed an NOI to be 

submitted for a group of wells within 

the same geologic formation. One 

commenter suggested that the rule be 

required to specify the location of all 

wells where fracturing will take place. 

The commenter was concerned that if 

this is not specified, and notice is 

submitted in the form of a Sundry 

Notice for a group of wells, the location 

of each well will not be clear. The BLM 

disagrees with the commenter. 

Operators use Sundry Notices (Form 

3160–5) to request approval to conduct 

operations and to subsequently report 

on operations after they are finished. 

Sundry Notices are used for all 

operations, not just hydraulic fracturing, 

and have been required for many years. 

The Sundry Notice form itself requires 

the operator to identify the lease 

number, the well number, and the 

location of the well. If a Sundry Notice 

is submitted for multiple wells, the 

Sundry Notice must contain a list of all 

of the wells including the lease number 

for each well and the legal land 

description of the location of each well. 

While this is not explicitly stated in the 

rule, the Sundry Notice form requires it. 

No revisions to the rule were made as 

a result of this comment. 

Submission of State/Tribal Data 

Numerous commenters said that in 

states where there is already a 

regulatory process for hydraulic 

fracturing, an operator should be 

allowed to submit the same information 

to the BLM as it does to the state. Both 

the supplemental and final rules 

include provisions that address the 

commenters concern. The first (section 

3162.3–3(d)) allows information 

submitted in accordance with state law 

to be submitted to the BLM if the 

information meets the standards of this 

rule. The second (section 3162.3–3(k)) 

allows the BLM to issue a statewide or 

regional variance to use particular state 

or tribal regulations and processes for 

permitting hydraulic fracturing 

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operations if they meet or exceed the 

objectives of this rule. Because the 

commenter’s concerns were already 

addressed in the rule, no changes were 

made as a result of these comments. 

One commenter requested that the 

BLM clarify the following statement in 

section 3162.3–3(d): ‘‘If information 

submitted in accordance with state (on 

Federal lands) or tribal (on Indian lands) 

laws or regulations meets the standards 

prescribed by the BLM, such 

information may be submitted to the 

BLM as part of the Sundry Notice.’’ This 

language has been clarified in the final 

rule. Many of the comments received in 

response to the initial proposed rule and 

the supplemental proposed rule were 

critical of duplication between state or 

tribal regulations and the supplemental 

proposed rule. The statement in this 

section is meant to address those 

concerns and minimize any duplication. 

If the information submitted to states or 

tribes meets the standards in this 

section, the operator does not need to 

generate any new information. 

Operators may submit the information 

that was generated to meet the state or 

tribal requirements to the BLM. To 

better reflect the BLM’s intent, the 

statement has been modified in the final 

rule for additional clarity, although no 

substantive change was made to the 

statement. 

Restructure Items for Clarity 

Some commenters recommended that 

sections 3162.3–3(d)(3) and 3162.3– 

3(d)(4) be restructured to add clarity to 

the requirements. Commenters said that 

the information required in section 

3162.3–3(d)(3) of the supplemental 

proposed rule included the proposed 

measured depth of the perforations or 

the open-hole interval and included 

information concerning the source and 

location of the water to be used during 

hydraulic fracturing. While this 

information is still needed, the items are 

distinct, and therefore should be 

separate requirements. The BLM agrees 

with these comments and sections 

3162.3–3(d)(3) and 3162.3–3(d)(4) are 

restructured in the final rule. Section 

3162.3–3(d)(3) now requires information 

concerning the source and location of 

the water supply. In addition, the 

requirement for the measured depth of 

the proposed perforated or open-hole 

interval is moved to section 3162.3– 

3(d)(4)(v). The information regarding the 

proposed perforated interval is now a 

distinct requirement, and this 

information relates more closely with 

the other information required by 

section 3162.3–3(d)(4). 

Identification of Usable Water 

Some commenters expressed concern 

that the requirement to identify usable 

water zones placed an increased and 

substantial burden on operators. The 

commenters stated that the current 

practice is not for operators to identify 

‘‘usable water’’ zones for protection and 

then submit the information to state oil 

and gas agencies or BLM offices for 

approval, but instead for these agencies 

to prescribe to operators which zones 

must be protected. The commenters’ 

perception of existing requirements is 

incorrect. Section III.D.3.b. of Onshore 

Order 1 requires operators to provide 

the estimated depth and thickness of 

formations, members, or zones 

potentially containing usable water, and 

the operator’s plans for protecting such 

resources. Section III.B. of Onshore 

Order 2 requires that the proposed 

casing and cementing programs be 

conducted as approved to protect and/ 

or isolate all usable water zones. It goes 

on to require that determination of 

casing setting depth must be based on 

all relevant factors, including usable 

water zones. It also requires that all 

indications of usable water be reported. 

This final rule requires the operator to 

identify the measured or estimated 

depths (both top and bottom) of all 

occurrences of usable water. This 

requirement is consistent with the 

existing requirements in Onshore 

Orders 1 and 2 and does not place an 

increased burden on the operators. No 

revisions to the rule were made as a 

result of these comments. The BLM 

agrees, however, that in many instances 

state or tribal oil and gas regulators, or 

water regulators, will be able to identify 

for operators some or all of the usable 

water zones that will need to be isolated 

and protected. 

One commenter recommended that 

the operator must inform the BLM of the 

locations, geologic formations, and 

depth of the usable water zones prior to 

initiating fracking operations. The 

commenter stated that this is of prime 

importance to people living in the 

vicinity of fracking and they need some 

certainty that the fracking operations 

will not impact their water resources. 

The BLM agrees. Some of this 

information is already required of the 

operators prior to drilling the well. 

Section III.D.3.b. of Onshore Order 1 

requires operators to provide the 

estimated depth and thickness of 

formations, members, or zones 

potentially containing usable water, and 

the operator’s plans for protecting such 

resources. The BLM uses this 

information in the evaluation of the well 

proposal to ensure that usable water 

zones are adequately protected by the 

proper placement of casing and cement. 

Since this information is already 

required to be submitted with the APD, 

it is not repeated in the rule. No 

revisions to the rule were made as a 

result of this comment. However, the 

information that would be required to 

be submitted as part of this rule will be 

made available to the public, consistent 

with the requirements of Federal law. 

Some commenters recommended 

using a research agency such as the 

United States Geological Survey (USGS) 

to identify usable water. Other 

commenters recommended developing 

Federal and state partnerships to map 

water resources. The BLM agrees that 

those entities can be helpful in 

identifying usable water. However, the 

BLM cannot mandate their 

participation. We note that the use of 

information developed by the USGS or 

state agencies is acceptable information 

for operators to use to identify usable 

water. In many areas, the USGS, state 

agencies, or tribal agencies have 

developed water resource maps. 

Operators may use this information, 

along with any other available 

information, including logs from nearby 

wells, to identify usable water zones. No 

revisions to the rule were made as a 

result of these comments. 

Section 3162.3–3(d) in the 

supplemental proposed rule required 

that the NOI include the measured or 

estimated depths (both top and bottom) 

of all occurrences of usable water by use 

of a drill log from the subject well or 

another well in the vicinity and within 

the same field. 

Many commenters expressed concern 

that identification of usable water by 

drill log is very difficult and expensive. 

Other commenters stated that the BLM 

is incorrect to assume that drill logs can 

be used to identify usable water. The 

commenters stated that these logs do not 

directly measure water quality or TDS. 

Operators often run resistivity logs for 

intermediate and production casing, and 

these logs might allow the qualitative 

identification of high salt content zones. 

These logs do not, however, directly 

measure TDS, and there are too many 

variables for the signature these logs 

record to be converted into accurate 

TDS data. Some commenters expressed 

concern that the term ‘‘drill log’’ is very 

broad and should be specifically 

defined. The BLM agrees with these 

comments. It was not the BLM’s intent 

to mandate a prescriptive method of 

estimating the depths of usable water. 

Final section 3162.3–3(d) has been 

revised and the phrase ‘‘by use of a drill 

log from the subject well or another well 

in the vicinity and with the same field,’’ 

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has been deleted in the final rule. This 

change will make the requirement less 

prescriptive, and it will make it 

consistent with the existing 

requirements in section III.D.3.b. of 

Onshore Order 1. 

Section III.D.3.b. of Onshore Order 1 

requires operators to provide the 

estimated depth and thickness of 

formations, members, or zones 

potentially containing usable water, and 

the operator’s plans for protecting 

usable water. It does not specify what 

information the operator must use to 

determine the estimated depth of usable 

water. The expectation is that the 

operator will use the best available 

information to estimate the depths of 

usable water. The expectation in this 

final rule is the same. Available 

information could include data and 

interpretation of resistivity logs run on 

nearby wells. In many areas, 

information can be obtained from state 

or tribal regulatory agencies. Many 

states have requirements that protect 

known water zones. For example, the 

North Dakota Industrial Commission 

requires that surface casing be set and 

cemented at a point not less than 50 feet 

below the base of the Fox Hills 

Formation (N.D. Admin Code 43–02– 

03–21 (2012)). The Wyoming Oil and 

Gas Conservation Commission uses 

regional water studies to identify known 

zones with potential to contain usable 

water such as the Fox Hills Formation 

in the Powder River Basin of Wyoming 

and bases its casing requirements on 

such information. Other information on 

usable water may be available from local 

BLM offices. For example, the BLM 

Pinedale Field Office Web site provides 

information regarding usable water. 

That Web site also provides typical 

casing and cementing designs for 

different areas under jurisdiction of the 

Field Office. 

Some commenters stated the rule will 

impose additional casing and/or 

cementing costs on operators because, 

unlike Onshore Order 2, the proposed 

rule would require cement behind pipe 

across all usable water zones. The 

commenters state that even though the 

proposed rule uses the word ‘‘isolate,’’ 

it uses the word differently than 

Onshore Order 2. The commenters go on 

to say this is clear from the requirement 

to run a CEL for each casing string that 

protects usable water. The BLM 

disagrees with these comments. The 

requirements in the supplemental 

proposed rule are consistent with the 

requirements in Onshore Order 2. For 

many wells, the isolation of usable 

water will be accomplished by setting 

cement across the usable water zones. 

However, in some wells, cementing 

across the usable water zone may not be 

feasible. In these situations, isolation of 

the usable water zones from any 

hydrocarbon bearing formations is 

warranted. The BLM modified some of 

the requirements in the final rule to 

eliminate confusion over the 

requirement to isolate and protect 

usable water. In the final rule, a CEL is 

not required on each string of surface 

casing that isolates usable water if 

certain performance standards are met. 

A few examples of performance 

standards to be met include cement 

return to surface, a successful formation 

integrity test confirming good cement 

bonding, and no lost circulation or other 

cementing problems. For wells where a 

CEL is required, the operator must run 

a CEL to demonstrate that there is at 

least 200 feet of adequately bonded 

cement between the zone to be 

hydraulically fractured and the deepest 

usable water zone. Meeting this 

requirement would demonstrate 

isolation and protection of the usable 

water zone from the zone to be 

hydraulically fractured. 

Another commenter recommended 

that all cementing requirements be 

eliminated from the rule. The 

commenter asserts that cementing 

operations are part of drilling operations 

and information is already submitted to 

state regulatory agencies for such 

operations. The commenter asserted that 

cementing operations have little to do 

with hydraulic fracturing. The BLM 

disagrees with this comment. While 

cementing information is already 

submitted to state regulatory agencies 

and the BLM, this rule expands on the 

requirements by including cement 

monitoring, cement remediation, and 

cement evaluation which are all related 

to protection of usable water from 

hydraulic fracturing operations. No 

revisions to the rule were made as a 

result of this comment. 

Identification of Water Sources and 

Access Routes 

Section 3162.3–3(d)(3) requires the 

operator to identify the anticipated 

access route for all water planned for 

use in fracturing the well. One 

commenter recommended that the BLM 

require the disclosure of all proposed 

and existing access routes, including 

those used to transport proppant (sand), 

equipment, and chemicals for use in the 

hydraulic fracturing fluids. The BLM 

disagrees with this comment. The BLM 

already requires the operator to submit 

its proposed access route to the well 

location in the APD (see Onshore Order 

1, section III.D.4.a.). In this rule, the 

BLM requires the operator to 

specifically identify the access route for 

the water to be used in fracturing 

operations because the access route 

from the water source may be 

potentially different from the route 

approved in the APD. The BLM uses 

this information provided by the 

operator to determine potential 

environmental impacts under NEPA and 

if a right-of-way to cross public lands is 

needed, and to assure compliance with 

other statues such as the FLPMA. All 

other travel to and from the location 

should be on the route described in the 

approved APD. However, the BLM has 

no authority to require its approval for 

transportation not on public lands. No 

revisions to the rule were made as a 

result of this comment. 

Some commenters disagreed with the 

requirement to provide information 

concerning the water source and 

location of water supply because they 

were unsure what the information 

would be used for, and others were 

concerned that the BLM would 

disapprove or condition the 

withdrawals, in violation of state 

authority over water use. Other 

comments stated that the water source 

could change and filing a Sundry Notice 

for the BLM to approve the change is 

burdensome. The BLM requires this 

information about the proposed source 

of the water in order to conduct and 

document an environmental effects 

analysis that takes a hard look at the 

impacts of its Federal action and meets 

the requirements of NEPA. The BLM has 

always required operators to file a 

Sundry Notice for changes to the 

approved permit—whether it is an APD 

or an NOI for hydraulic fracturing or for 

other operations requiring BLM 

approval. No changes to the final rule 

were made as a result of these 

comments. 

Some commenters stated that 

information regarding the water source 

would have already been provided as 

part of the APD. The BLM agrees in part. 

Section III.D.4.e. of Onshore Order 1 

requires the operator to identify the 

location and types of water supply to be 

used during the drilling operations in 

the APD. That water supply for such 

things as mixing drilling mud and 

cement may or may not be the same as 

the water supply for hydraulic 

fracturing operations, which often needs 

much greater quantities of water, but 

may be able to use water of different 

quality. Since the water supply may be 

different, this information must be 

included in the application for 

hydraulic fracturing. No revisions to the 

rule were made as a result of these 

comments. 

One commenter expressed concern 

about identifying the source and 

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location of reused or recycled water. 

The commenter stated that they will 

often send produced waters to a 

centralized recycle or reuse facility. 

These waters will not have one single 

source, and once commingled, could not 

readily be identified as coming from one 

particular well. The rule does not 

require the sources of water that the 

reuse or recycling facility receives. If the 

water is coming from a centralized 

recycling facility, identifying the water 

as reused or recycled, and providing the 

location of the recycling facility is 

sufficient for the information required 

in the permit application. 

One commenter requested 

clarification of the term ‘‘water supply.’’ 

The commenter said it was unclear 

whether the requirement was requesting 

the source and location of the water to 

be used in the hydraulic fracturing 

operation or if the requirement was 

requesting the source for drinking 

water/agricultural water/industrial 

water in the area. The requirement is 

referring to the source water used as a 

base fluid in the hydraulic fracturing 

operations. 

Another commenter recommended 

that the BLM strengthen the language 

regarding identification of the water 

supply to say ‘‘must’’ instead of ‘‘may.’’ 

The language in the rule requires the 

applicant to provide information on the 

source and location of the water supply, 

‘‘which may be shown by quarterquarter section on a map or plat, or 

which may be described in writing.’’ 

The BLM believes the rule is clear as 

written. The applicant must provide the 

information requested, but they have the 

option of either showing it on a map or 

plat, or by describing it in writing. No 

revisions to the rule were made as a 

result of these comments. 

Hydraulic Fracturing Plan—Water 

Volume 

The BLM received one comment 

suggesting that the BLM should require 

the operator to provide the volumes of 

water to be used during hydraulic 

fracturing operations in its application. 

Another commenter asked if section 

3162.3–3(d)(4)(i) refers to the volume of 

hydraulic fracturing fluid or the volume 

of water from the water supply. Section 

3162.3–3(d)(4)(i) requires the 

submission of the estimated total 

volume of fluid to be used. This 

requirement does not specifically 

require the volume of water. However, 

since most all of the fracking fluid is 

water (assuming a water-based 

fracturing fluid), it is a good indicator of 

the estimated volume of water to be 

used. Some hydraulic fracturing 

operations, however, use other fluids 

such as nitrogen or carbon dioxide. For 

these operations, the estimated total 

volume of fluid would include all 

fluids, including the nitrogen or carbon 

dioxide. 

Hydraulic Fracturing Plan—Pressures 

Several comments suggested 

clarification of the pressures required in 

the permit application (supplemental 

proposed rule section 3162.3–3(d)). In 

the supplemental proposed rule, 

paragraph (d)(3) would have required 

‘‘estimated pump pressures,’’ paragraph 

(d)(4)(ii) would have required the 

‘‘anticipated surface treating pressure 

range,’’ and paragraph (d)(4)(iii) would 

have required the ‘‘maximum injection 

treating pressure.’’ The commenters 

expressed some confusion over the need 

for the three different pressures and also 

some confusion over the terminology. 

The BLM agrees with these comments 

and consolidated the requirements in 

proposed paragraph (d) to one 

requirement to provide the ‘‘maximum 

anticipated surface pressure that will be 

applied during the hydraulic fracturing 

process’’ (final section 3162.3– 

3(d)(4)(ii)). The primary reason for 

requesting this information was to 

ensure the pressures used during the 

hydraulic fracturing process were no 

greater than the pressures used in the 

MIT (see section 3162.2–2(f)) prior to 

hydraulic fracturing and to ensure that 

the wellbore is adequately designed to 

handle these pressures. Therefore, the 

requirement for ‘‘pressure ranges’’ in the 

supplemental proposed rule (paragraph 

(d)(4)(ii)) is not necessary—only the 

maximum pressure is required for the 

intended purpose. The phrase ‘‘treating 

pressure’’ is eliminated because the 

meaning of the word ‘‘treating’’ may not 

be universally understood. 

Also in response to these comments, 

the BLM changed the wording in 

sections 3162.3–3(f)(1) and (i)(3) of the 

final rule to match the terminology used 

in section 3162.3–3(d)(4)(ii). 

Hydraulic Fracturing Plan—Fracture 

Data 

The BLM received several comments 

regarding the submittal of fracture 

design information. Some commenters 

fully supported the requirement. These 

commenters indicated the data is 

necessary for BLM evaluation. These 

commenters were in general agreement 

with the provisions of this section, e.g., 

fracture length, height, and direction 

data can be actual, estimated, or 

calculated. 

Some commenters objected to 

allowing fracture design estimates 

instead of actual fracturing data and 

other commenters requested that the 

data submitted include three 

dimensional reservoir and fracturing 

modeling. The primary objective of the 

additional requirements requested by 

the commenters was to give the BLM 

better information to ensure that the 

fractures would not extend into any 

usable water zones or intersect other 

wells (i.e., ‘‘frack hits’’). The BLM did 

not make any changes to the rule as a 

result of these comments for several 

reasons. First, information presented in 

an application is only estimated because 

actual conditions encountered during 

the drilling and hydraulic fracturing 

process can change significantly from 

the conditions anticipated in the 

application as operations progress. 

Therefore, any modeling would be 

calculated from best estimates of 

conditions, introducing significant 

uncertainty in the calculations as to 

render them no more useful than the 

estimated fracture data required in the 

proposed rule. Second, the intent of 

requiring this information in the 

hydraulic fracturing application is to 

give the BLM a general idea of the 

extent of the fractures as a tool to 

identify potential hazards such as other 

wells and to assure that there will be 

adequate margins of protection for the 

closest zone containing usable water. 

Exact calculations, speculative or not, 

are not required under this section of 

the final rule. Although no changes to 

the rule were made directly as a result 

of these comments, the final rule does 

expand the informational requirements 

relating to fractures and potential frack 

hits. Under the final rule, operators 

must submit the estimated fracture data 

on a map that also shows all known 

wellbore trajectories within one-half 

mile of the well that is proposed to be 

fractured. 

The BLM also received numerous 

comments objecting to the requirement 

to specify the fracture length in the 

application for hydraulic fracturing. 

Several commenters stated that 

expensive modeling would be required 

to estimate fracture length. As discussed 

earlier, although it can be used, 

modeling is not required. The intent of 

this requirement is to provide the BLM 

with enough information about the 

proposed hydraulic fracturing operation 

that potential hazards, such as other 

wells and fracture propagation into 

usable water zones, can be identified 

and mitigated. Estimated fracture 

dimensions are sufficient to meet this 

intent. Because the rule already requires 

‘‘estimated or calculated’’ fracture data, 

no changes to the rule were made as a 

result of the comments. 

A few commenters expressed concern 

about confidentiality of the information 

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in providing the required details on the 

estimated fracture length, height, and 

direction. The BLM believes that the 

submission of these estimated values 

would not routinely meet any of the 

criteria within the Freedom of 

Information Act regulations (43 CFR 

part 2) which would require such 

information to be held as confidential 

information. The BLM did not revise the 

rule as a result of these comments. 

One commenter said that fracture data 

has nothing to do with wellbore 

integrity or protecting groundwater. The 

BLM disagrees. One of the purposes of 

submitting fracture estimates is to allow 

the BLM to analyze hydraulic fracturing 

proposals for potential interference with 

other wells. There is a potential for 

groundwater contamination if highpressure hydraulic fracturing fluid 

intersects the drainage radius of another 

wellbore. The BLM did not revise the 

rule as a result of these comments. 

Meaning of ‘‘Wellbore’’ 

In response to comments, the BLM 

determined that it should be made clear 

that the rule was not requiring only the 

locations of vertical segments of wells. 

The rule at paragraph (d)(4)(iii)(C) 

requires submission of a map showing 

the location of all wellbores within onehalf mile horizontally of the wellbore to 

be hydraulically fractured. A wellbore is 

not merely the vertical component of a 

well. A wellbore is commonly 

understood to be ‘‘[t]he hole made by a 

well.’’ Williams & Myers Manual of Oil 

& Gas Terms, p.1173 (10th ed. 1997). It 

thus includes all vertical, directional, 

and horizontal legs of a well. Thus, any 

part of an existing well that comes 

within one-half mile horizontally of the 

trajectory of the well to be hydraulically 

fractured (regardless of any difference in 

depths) must be shown on the map 

submitted with the operator’s 

application. The information will allow 

the authorized officer to work with the 

operator to prevent ‘‘frack hits.’’ 

Distance to Aquifers 

The BLM received a few comments 

regarding the vertical distance from the 

intended hydraulic fracture zone to the 

nearest aquifer. One commenter 

recommended that the rule be revised to 

require the operator to report the 

vertical distance from the intended 

hydraulic fracture zone to the nearest 

aquifer. The BLM did not revise the rule 

as a result of these comments since this 

is already required in final section 

3162.3–3(d)(4)(iv) for all requests for 

approval of hydraulic fracturing. 

Some commenters recommended that 

the rule be modified to clarify the 

requirement regarding the NOI 

estimated vertical distance to the 

nearest usable water aquifer above the 

fracture zone. The commenters 

indicated that the BLM should specify 

if this is the distance between the 

surface down to the aquifer or the 

distance between the aquifer to the 

fracture zone. The BLM agrees that the 

proposed language was unclear and has 

modified the rule as a result of these 

comments. The intent of this section is 

to estimate the vertical distance between 

the top of the fracture zone and the 

nearest usable water zone. The BLM 

believes that this information is 

necessary to properly evaluate the 

potential impacts of a hydraulic 

fracturing proposal and had revised the 

language accordingly. 

Handling of Recovered Fluids 

Some commenters stated that 

requiring disclosure of proposed 

methods of handling the recovered 

fluids prior to drilling is an 

unreasonable administrative burden for 

operators when the requirement does 

nothing to further protect public health 

and welfare, the environment, nor 

facilitate efficient production. The BLM 

disagrees with these comments. The 

BLM requires the information about the 

handling of recovered fluids in order to 

conduct and document an 

environmental effects analysis that takes 

a hard look at the impacts of its Federal 

action and meets the requirements of 

NEPA and to assure that recovered 

fluids will not contaminate resources on 

or in public lands or Indian lands. 

Other commenters requested that this 

section be expanded to include language 

that requests amounts, locations, 

facilities for storage, and options for 

recovering fluids for treatment. The rule 

requires reporting to the BLM of 

estimated volumes of recovered fluid 

along with the proposed methods of 

handling and disposal of those fluids. 

The BLM believes the information 

required in the final rule addresses the 

commenter’s concern and is adequate to 

assess any potential impacts from the 

proposed methods of handling the 

produced fluids and to ensure 

protection of resources. No changes 

were made to the final rule based on 

this comment. 

Commenters asked why the estimated 

chemical composition of the flowback 

fluid is required, and requested this 

requirement be struck from the rule. 

While the original proposed rule 

required the operator to submit the 

estimated chemical composition of the 

flowback fluid, the supplemental 

proposed rule did not. The rationale for 

deleting the requirement was discussed 

in the preamble of the supplemental 

proposed rule. This final rule does not 

require the estimated chemical 

composition of the flowback and 

therefore the BLM did not revise the 

rule as a result of these comments. 

Additional Data 

Some commenters recommended that 

section 3162.3–3(d)(7), which allows the 

authorized officer to request additional 

information prior to the approval of the 

NOI, be deleted. The commenters 

expressed concern that the provision 

creates too much uncertainty for 

operators and does not include any 

standards under which the BLM can 

request additional information. The 

BLM believes that the provision in the 

rule is necessary to provide the 

flexibility essential to regulating 

operations over a broad range of 

geologic and environmental conditions. 

Any new information that the BLM may 

request will be limited to information 

necessary for the BLM to ensure that 

operations are consistent with 

applicable laws and regulations, or that 

the operator is taking into account sitespecific circumstances. Requests for 

information from the authorized officer 

are subject to administrative review if 

an operator believes the directive lacks 

a proper basis. The BLM did not revise 

the rule as a result of these comments. 

Duplication of State Process 

Several commenters stated that many 

parts of the rule are duplicative of state 

requirements, and therefore were 

unnecessary and would increase the 

regulatory and permitting burdens on 

operators. Some of the comments were 

generic while others specifically 

identified states such as Colorado, New 

Mexico, and Wyoming. The BLM has 

determined that the collections of 

information in the rule are necessary to 

enable the BLM to meet its statutory 

obligations to regulate operations 

associated with Federal and Indian oil 

and gas leases; prevent unnecessary or 

undue degradation; and manage public 

lands using the principles of multiple 

use and sustained yield; and protect 

resources associated with Indian lands. 

The information that states, tribes, or 

other Federal agencies collect is neither 

uniform nor uniformly accessible to the 

BLM. For these reasons, the BLM has 

determined that the collections in the 

rule are necessary, and are not 

unnecessarily duplicative of existing 

Federal, tribal, or state collection 

requirements. If the data required by a 

state is the same as the data required by 

this rule, it is permissible for the 

operator to attach it to the APD or NOI 

required for Federal and Indian lands, 

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thus substantially reducing the 

reporting burden for operators. 

Timeframes 

Some commenters were concerned 

over possible delays in BLM approval of 

their applications and requested that the 

BLM include processing timeframes in 

the rule. Specific timeframes suggested 

were from 10 to 30 days. Some 

commenters recommended that the 

permit be automatically approved after 

30 days. Other commenters did not offer 

any specific suggestions on timeframes. 

The BLM did not revise the rule as a 

result of these comments because the 

imposition of a timeframe or 

‘‘automatic’’ approvals could limit the 

BLM’s ability to ensure protection of 

usable water and other resources. The 

BLM cannot abdicate its statutorily 

mandated responsibilities to prevent 

unnecessary or undue degradation of 

public lands and to protect Federal and 

Indian resources by establishing an 

arbitrary deadline. Furthermore, the 

BLM has obligations to assure 

compliance with relevant statutes and 

Executive Orders, which in some cases 

would require more than 30 days. As 

discussed in other sections, however, 

the rule would make several changes to 

the permitting process that could reduce 

the potential for processing delays. 

Flowback Fluid 

One commenter suggested that the 

BLM allow the flowback data required 

in section 3162.3–3(d)(5) of the 

supplemental proposed rule to be 

submitted either in the Sundry Notice or 

through a database. The BLM did not 

revise the rule because there is no 

existing database suitable for that 

purpose and the BLM believes that 

submission under this final rule is 

adequate. However, the BLM is 

considering expanding the use of its 

Well Information System for electronic 

submittal of various types of Sundry 

Notices. 

One commenter requested that the 

BLM require operators to have a water 

management plan for flowback fluid. No 

changes to the rule were made as a 

result of this comment because the BLM 

requires the equivalent of a water 

management plan in final section 

3162.3–3(d)(5) of the rule. 

Approval Standards 

Several commenters suggested that 

the BLM define clear standards for 

approving or denying an application for 

hydraulic fracturing. No changes to the 

rule were made as a result of this 

comment because the decision to 

approve or deny a particular application 

will be made by the authorized officer 

based on the site-specific conditions for 

that application and based on whether 

or not the application complies with 

this rule and applicable law. 

Section 3162.3–3(e) Cement 

Monitoring 

This section requires operators to: 

• Monitor and record their cementing 

operations—This is consistent with 

industry guidance stressing the 

importance of using data from reports, 

logs, and tests to evaluate the quality of 

a cement job, including drilling reports, 

drilling fluid reports, cement design and 

related laboratory reports, open-hole log 

information including caliper logs, and 

cement placement information 

including a centralizer program, 

placement simulations and job logs, etc.; 

• Cement the surface casing to the 

surface—This is already required by 

Onshore Order 2 and most state 

regulations, and is consistent with 

industry practice; 

• For both the intermediate and 

production casing strings where they 

serve to protect usable water, the 

operator must either cement to the 

surface or run a CEL to demonstrate that 

there is at least 200 feet of adequately 

bonded cement between the deepest 

usable water zone and the formation to 

be fractured. This is generally consistent 

with industry guidance and specified in 

some state regulations. The American 

Petroleum Institute’s (API) guidance 

titled ‘‘Hydraulic Fracturing OperationsWell Construction and Integrity 

Guidelines, First Edition, October 

2009,’’ commonly known as HF1, states 

that ‘‘if the intermediate casing is not 

cemented to the surface, at a minimum, 

the cement should extend above any 

exposed USDW or any hydrocarbon 

bearing zone’’ and that operators may 

run a CEL and/or other diagnostic tools 

to determine the adequacy of the cement 

integrity and that the cement reached 

the desired height. 

If there is an indication of inadequate 

cement, the operator must notify the 

BLM within 24 hours, submit a plan to 

perform remedial action, verify that the 

remedial action was successful with a 

CEL or other approved method, and 

submit a subsequent report including a 

signed certification and results of the 

corrective action. 

Section (e)(1) of the final rule is 

revised to require submission of the 

cement monitoring report to the BLM at 

least 48 hours prior to commencing 

hydraulic fracturing operations, instead 

of 30 days after the completion of 

hydraulic fracturing operations, as was 

proposed in the supplemental proposed 

rule. The BLM made this change to 

allow field office engineers time to 

review the cement monitoring report, 

consistent with ensuring wellbore 

integrity. The 48-hour period will allow 

the BLM sufficient time to review the 

report, while not creating an 

unreasonable burden on the operators. 

In most wells, any usable water is 

isolated with the surface casing that is 

set many days or even months before 

the well reaches total depth, so there is 

plenty of time for the operator to submit 

the report. For wells where usable water 

is isolated by intermediate or 

production casing, the operator would 

still have ample time to submit the 

cement monitoring report. Typically, 

after the operator completes drilling and 

cementing operations, the operator 

moves the drilling rig off the well and 

moves on a completion rig with 

hydraulic fracturing following. This 

transition period will allow the 

operators sufficient time to submit the 

cement operations monitoring report at 

least 48-hour prior to commencing 

hydraulic fracturing. 

For any well completed pursuant to 

an APD that did not expressly authorize 

hydraulic fracturing operations, there is 

a new section 3162.3–3(e)(1)(ii) that 

requires the operator to submit 

documentation to demonstrate that 

adequate cementing was achieved for all 

casing strings designed to isolate or to 

protect usable water. The operator must 

submit the documentation with its 

request for approval of hydraulic 

fracturing operations, or no less than 48 

hours prior to conducting hydraulic 

fracturing operations if no prior 

approval is required pursuant to 

paragraph 3162.3–3(a). The authorized 

officer may approve the hydraulic 

fracturing of the well only if the 

documentation provides assurance that 

the cementing was sufficient to isolate 

and to protect usable water, and may 

require such additional tests, 

verifications, cementing, or other 

protection or isolation operations, as the 

authorized officer may deem necessary. 

This provision would apply to wells 

subject to the transition period as shown 

in the table in section 3162.3–3(a), and 

to other wells that might have been 

completed as conventional wells or 

fractured prior to this rule, but 

subsequently are proposed to be recompleted by hydraulic fracturing. 

Many if not most operators would have 

the information required in section 

3162.3–3(e)(1)(i), and could readily 

provide it to the authorized officer. 

However, if the operator did not 

maintain all of those records, it could 

provide the available information to the 

authorized officer, who could approve 

the operator’s request once there is 

assurance that the hydraulic fracturing 

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operation in the well would be 

consistent with the requirements of 

proper isolation and protection of the 

usable water zones. 

Sections 3162.3–3(e)(2) and (e)(3) of 

the supplemental proposed rule were 

deleted in the final rule and replaced by 

a new section 3162.3–3(e)(2). The 

supplemental proposed rule (section 

3262.3–3(e)(2)) used a ‘‘type well’’ 

concept and would have required that a 

CEL be run on all casing strings that 

protect usable water unless the well was 

permitted with an NOI for a group of 

wells, was drilled with the same 

specifications and geologic 

characteristics as the type well, the 

cementing operations monitoring data 

paralleled the type well, and the type 

well CEL indicated successful cement 

bonding (section 3162.3–3(e)(3) of the 

supplemental proposed rule). The final 

rule no longer requires a CEL to be run 

on all casing strings that protect usable 

water and the type well provisions in 

the supplemental rule are deleted. 

Instead, section 3162.3–3(e)(2) of this 

rule sets performance standards for 

ensuring adequate cement bonding on 

all casing that protects usable water and 

applies to all wells, not just type wells. 

For casing strings that are cemented to 

the surface, which includes surface 

casing, the primary indicator of 

adequate cement bonding is cement 

monitoring. This includes such criteria 

as good returns to the surface, the 

absence of gas-cut mud, and properly 

functioning equipment throughout the 

cement job. The final rule also includes 

a criterion (10 percent of casing setting 

depth or 200 feet, whichever is less) for 

the amount of allowable fall-back. The 

BLM believes that these criteria will 

more effectively and less subjectively 

ensure the protection of usable water on 

all wells that will be hydraulically 

fractured than the CEL that would have 

been required in the supplemental 

proposed rule. 

For intermediate and production 

casing designed to protect usable water 

and where cement is not brought to the 

surface, this final rule requires that a 

CEL demonstrate that there is at least 

200 feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. The supplemental proposed rule 

would have only required a CEL in this 

situation if the well was defined as a 

type well or if there were indications of 

an inadequate cement job. However, 

indications of an inadequate cement job 

are much more difficult to observe when 

cement is not brought to the surface. 

Therefore, the final rule requires a CEL 

on all intermediate or production casing 

strings designed to protect usable water 

when the cement is not circulated to the 

surface. This section also defines the 

amount of adequately bonded cement 

necessary to allow hydraulic fracturing, 

which was not defined in the 

supplemental proposed rule. 

The BLM made several revisions to 

section 3162.3–3(e)(3) of the final rule 

(section 3162.3–3(e)(4) of the 

supplemental proposed rule), which 

address the course of action an operator 

must take if there are indications of an 

inadequate cement job. The final rule 

explicitly requires the operator to 

submit an NOI to the BLM for approval 

of remedial action to address inadequate 

cementing, where the supplemental 

proposed rule would have only required 

the operator to report the remedial 

action to the BLM. The BLM believes 

that the final rule’s requirement that the 

operator receive BLM approval prior to 

remediating inadequate cementing will 

help to ensure protection of aquifers. 

The final rule also establishes a 

procedure for granting approval to take 

remedial action in emergency situations. 

The supplemental proposed rule 

would have required the operator to 

submit a written report to the BLM 

within 48 hours of discovering an 

inadequate cement job. The final rule 

requires the submission of an NOI for 

BLM approval in lieu of the written 

report and also deletes the 48-hour 

timeframe. The BLM believes that in 

most cases prompt submission of an 

NOI would be in the operator’s best 

interest because they cannot proceed 

with hydraulic fracturing until the NOI 

is approved and therefore the 48-hour 

timeframe is unnecessary. Both the 

supplemental proposed rule and the 

final rule require the operator to run a 

CEL verifying that the remedial action 

was successful. 

Final section 3162.3–3(e)(3) contains 

revised requirements for what an 

operator must do if there are indications 

of an inadequate cement job. In the 

supplemental proposed rule (section 

3162.3–3(e)(4)), prior to commencing 

hydraulic fracturing, the operator would 

have been required to notify the BLM 

within 24 hours, submit a written report 

within 48 hours, run a CEL showing the 

inadequate cement had been corrected, 

and at least 72 hours prior to 

commencing operations, submit a 

certification and documentation 

indicating the cement job had been 

corrected. 

However, the supplemental proposed 

rule did not have a provision that would 

have allowed the BLM to review the 

documentation required or approve a 

plan for remedial action. The final rule 

requires the operator to notify the BLM 

within 24 hours and submit an NOI to 

the BLM for remedial action along with 

supporting documentation and logs. 

This gives the BLM the opportunity to 

review the documentation and logs 

submitted to ensure that the remedial 

action proposed by the operator is 

appropriate. The requirement to submit 

an NOI takes the place of the 48-hour 

written notification in the supplemental 

proposed rule, although the BLM 

determined that no timeframe is 

required because the operator will be 

required to submit the NOI and receive 

approval prior to commencing 

fracturing operations. 

Type Well CEL 

Very few commenters were 

supportive of the type well concept for 

cement evaluation. In the supplemental 

proposed rule, a type well CEL would 

have been required to demonstrate 

successful cement bonding; thereafter, 

other wells in an approved group would 

not have been required to have a CEL 

unless there were indications of 

inadequate cement. The subsequent 

wells would also have needed to have 

the same specifications and geologic 

characteristics as the type well, and the 

cementing operations monitoring data 

would have needed to parallel that of 

the type well. Many commenters stated 

that the definition of a type well was too 

vague. Some commenters wanted the 

BLM to limit the type well concept to 

a certain number of wells, to a certain 

distance between wells, or to a certain 

time between the hydraulic fracturing of 

wells. Other commenters recommended 

requiring a minimum number of 

successful wells rather than just a single 

type well. Other commenters wanted 

the type well concept to be greatly 

expanded to include all wells within a 

county or within a geologic basin. Many 

commenters stated that successful 

cementing operations on one well were 

not indicative of subsequent successful 

cementing of another well, regardless of 

the proximity. Some commenters 

wanted a clearer, more specific set of 

standards and procedures to guide the 

determination of what constitutes a type 

well for a given set of wells. Other 

commenters were critical that the rule 

did not elaborate upon the meaning of 

‘‘substantially similar geological 

characteristics within the same geologic 

formation’’ (language used in the 

definition of type well) or the manner in 

which the BLM makes that 

determination. Still others expressed 

concern that the use of type wells 

assumes that geologic zones are 

compositionally, texturally, and 

mechanically homogeneous media, even 

though this is often not true. Other 

commenters stated the type well 

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approach fails to address risk by 

ignoring fundamental geologic 

principles and sound engineering 

practice. Other commenters stated the 

type well concept allows the BLM to 

bring significant judgment to the well 

permitting process rather than specific 

standards. 

After reviewing the comments on the 

use of type wells, type wells are 

eliminated from the final rule. The BLM 

agrees that successful cementing 

operations on one well are not 

necessarily indicative of subsequent 

successful cementing of another well 

regardless of the proximity or geologic 

characteristics, and that implementation 

of the type well concept would be 

difficult to achieve. Rather than 

restructure the definition, or develop a 

specific set of standards, the BLM 

instead made the decision to eliminate 

the type well concept and to establish 

cementing operations monitoring 

requirements and usable water isolation 

requirements that apply to every well. 

CEL 

Numerous commenters objected to the 

requirement to run a CEL on each casing 

string that protects usable water. Many 

of these commenters stated that the use 

of CELs on surface casing is 

unprecedented for onshore wells. The 

commenters pointed out that state 

regulations do not require CELs on 

surface casing and that API guidelines 

do not mention cement logs in the 

section specifically devoted to surface 

casing. Many commenters stated that 

where cement is circulated to the 

surface and pressure tests are 

satisfactory, CELs do not provide any 

additional assurance of protection. 

Many commenters were concerned 

about the costs associated with running 

a CEL on surface casing. Many other 

commenters said that CELs are not 

commonly run on surface and 

intermediate casing unless other 

indicators of an unsuccessful cement job 

are present. Many of the commenters 

were critical that the BLM was relying 

on the CEL as the ‘‘sole diagnostic tool’’ 

to evaluate cement integrity. Many 

commenters stated that CEL data can be 

difficult to interpret properly and often 

yields false positives. The BLM agrees 

with many of these comments and has 

revised the final rule as a result. The 

final rule does not require a CEL on the 

surface casing unless there are 

indications of inadequate cement. Final 

section 3162.3–3(e)(2)(i) requires that 

the operator determine that there is 

adequate cement for surface casing used 

to isolate usable water zones. The 

operator must observe cement returns to 

the surface and document any 

indications of inadequate cement (such 

as, but not limited to, lost returns, 

cement channeling, gas cut mud, failure 

of equipment, or fallback from the 

surface exceeding 10 percent of surface 

casing setting depth or 200 feet, 

whichever is less). If there are 

indications of inadequate cement, then 

under final section 3162.3–3(e)(2), the 

operator must determine the top of 

cement with a CEL, temperature log, or 

other method or device approved by the 

authorized officer. 

Many other commenters 

recommended that a CEL be required on 

every string of casing in every well. 

Commenters expressed concern that 

anything less would greatly increase the 

risk of contamination. The commenters 

were opposed to allowing operators to 

run CELs on type wells only. The 

commenters expressed the view that 

CELs are the only way to ensure 

adequate cementing of the casing on 

each well. 

Numerous other commenters stated 

that the best way to confirm the 

adequacy of a cement job is through 

proper monitoring of the cementing 

operations and direct observation of a 

variety of factors; the most important 

being cement returns to the surface. 

Many commenters expressed concern 

about the reliability of CELs, stating that 

CEL data can be difficult to interpret 

properly and often yield false positives. 

Commenters said that this can lead to 

unnecessary attempts at remediation, 

which will actually weaken the 

wellbore integrity. 

Some commenters said that allowing 

operators to use CELs, rather than just 

CBLs, alleviates some, but not all of the 

interpretation concerns. Other 

commenters stated that CBLs are not 

effective until the cement has reached a 

certain compressive strength because 

CBLs work on the principle of acoustic 

attenuation. At low compressive 

strengths, commenters stated that the 

acoustic properties of cement and water 

are very similar and it is difficult to 

delineate between the two when 

interpreting logs. The commenters went 

on to state that the problem is also 

inherent in the CELs, which can 

sometimes provide a risky basis for 

evaluating the integrity of the cement. 

The commenters claim that the logs do 

not ‘‘see’’ the cement. The logs merely 

allow a competent professional to draw 

inferences about the evenness of the 

cementing around the pipe, based on 

readings of sonic or ultrasonic waves 

passing through the pipe into the 

cement and the rock beyond. The 

commenters quoted API Technical 

Report 10TR1, September 2008, which 

cautions that cement bond log 

interpretation ‘‘is not recommended as a 

best practice for cement evaluation.’’ 

After further researching these 

concerns, the BLM agrees that the 

monitoring of data and direct 

observations of various factors, 

including cement return to the surface, 

are good indicators of an adequate 

cement job, and the BLM acknowledges 

the potential difficulties of running and 

interpreting CELs. As a result, the BLM 

has determined that requiring CELs on 

the surface casing of every well will not 

provide increased protection beyond 

cement operations monitoring and 

circulation of cement to the surface. 

Therefore, the final rule requires 

operators to monitor their cementing 

operations, including verification of 

cement returns to the surface, and to 

submit the cementing operations 

monitoring report to the BLM prior to 

commencing hydraulic fracturing 

operations. 

Some commenters disagreed with the 

proposed regulation allowing the 

operator to wait to submit a cement 

monitoring operations report to the BLM 

until after completion of the hydraulic 

fracturing operations. These 

commenters said that the operator 

should submit the report to the BLM 

prior to the commencement of hydraulic 

fracturing operations. The BLM agrees 

and revised the rule as a result of these 

comments. Final section 3162.3–3(e)(1) 

requires that during cementing 

operations on any casing used to isolate 

usable water zones, the operator must 

monitor and record the flow rate, 

density, and pump pressure and submit 

a cement operation monitoring report, 

including that information, to the 

authorized officer at least 48 hours prior 

to commencing hydraulic fracturing 

operations, unless the authorized officer 

approves a shorter time. This would 

allow the BLM time to review the 

monitoring report to verify compliance 

with these regulations. If the monitoring 

report indicates problems with the 

cementing operations, the operator must 

correct the issue prior to hydraulically 

fracturing. 

The final rule also has more specific 

criteria for the operator to follow to 

determine that there is adequate cement 

for all casing strings used to isolate 

usable water zones. Onshore Order 2 

(section III.B.1.c.) requires surface 

casing in all wells to be cemented to the 

surface. For surface casing, this final 

rule requires the operator to observe 

cement returns to the surface and to 

document any indications of inadequate 

cement (such as, but not limited to, lost 

returns, cement channeling, gas cut 

mud, failure of equipment, or fallback 

from the surface exceeding 10 percent of 

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surface casing setting depth or 200 feet, 

whichever is less). If there are 

indications of inadequate cement, then 

the operator must determine the top of 

the cement with a CEL, temperature log, 

or other method or device approved by 

the authorized officer. For intermediate 

or production casing, this rule requires 

that if the casing is not cemented to the 

surface, then the operator must run a 

CEL to demonstrate that there is at least 

200 feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. If the casing is cemented to 

surface, then the operator must follow 

the surface casing cementing 

requirements. 

The BLM believes that the final rule’s 

requirements described earlier, in 

conjunction with the casing and 

cementing requirements of Onshore 

Order 2, will sufficiently isolate and 

protect usable water. As discussed 

earlier, Onshore Order 2 (section 

III.B.1.c.) requires that the operator 

cement the surface casing to the surface. 

Onshore Order 2 (section III.B.1.f.) also 

requires that the surface casing shall 

have centralizers on the bottom three 

joints of casing in order to keep the 

casing in the center of the wellbore to 

help ensure efficient placement of 

cement around the casing string. 

Onshore Order 2 (section III.B.1.h.) 

requires the operator to pressure test all 

casing strings to ensure the integrity of 

the casing. Onshore Order 2 (section 

III.B.1.i.) also requires a pressure 

integrity test of each casing shoe on all 

exploratory wells and on that portion of 

any well approved for a 5M (5,000 

pounds per square inch) BOPE (blowout 

preventer equipment). This test insures 

that a good, leak-tight cement job has 

been obtained. 

Final section 3162.3–3(e) strengthens 

the requirements that operators must 

follow when there is an indication of 

inadequate cementing. The operator 

must notify the authorized officer 

within 24 hours of discovering the 

inadequate cement. For the surface 

casing, this will likely be immediately 

following the cementing operations. For 

intermediate or production casing that 

is not cemented to the surface, this may 

not be until after the operator has run 

the CEL. Early notification will ensure 

that the BLM is involved with the 

remediation of the cement. Under the 

final rule the operator must submit an 

NOI to the authorized officer requesting 

approval of a plan to perform remedial 

action to achieve adequate cement. The 

plan must include supporting 

documentation and logs. The BLM will 

review the plan, work with the operator 

to modify the plan if necessary, and 

attach any conditions of approval to the 

plan. Upon approval, the operator can 

commence the remedial actions. After 

completing the remediation process, the 

operator must verify that the remedial 

action was successful with a CEL or 

other method approved in advance by 

the authorized officer. The operator 

must submit a subsequent report for the 

remedial action, including a signed 

certification that the operator corrected 

the inadequate cement job in 

accordance with the approved plan, and 

the results from the CEL or other 

method approved by the authorized 

officer and documentation showing that 

there is adequate cement. As required 

by existing section 3160.0–9(c), the 

subsequent report is due 30 days after 

the operations are completed. This final 

rule, however, also requires the operator 

to submit the results from the CEL or 

other method approved by the 

authorized officer at least 72 hours 

before starting hydraulic fracturing 

operations. This will provide the BLM 

the opportunity to verify the 

remediation process was successful and 

that will help to ensure adequate 

protection of aquifers in advance of 

hydraulic fracturing operations. 

Conductor Pipe 

Several commenters said that section 

3162.3–3(e) should be modified to 

specify that a CEL requirement does not 

apply to conductor pipe. The BLM 

agrees with this comment and has 

modified the rule at sections 3162.3– 

3(e)(1) and 3162.3–3(e)(2) to clarify that 

CELs are only required on casing strings 

designed to protect usable water. 

Conductor pipe does not typically 

protect aquifers. Conductor pipe is a 

large diameter pipe set to relatively 

shallow depths which serves as a 

conduit for all other casings and well 

operations. The formations close to the 

surface are often unconsolidated and 

during the commencement of drilling 

operations these formations erode or 

wash out from the circulating drilling 

muds. The conductor pipe’s purpose is 

to prevent this near-surface erosion from 

interfering with subsequent drilling and 

operating activities. Based on the 

surface formation’s conditions, certain 

wells do not have conductor casing set, 

in other instances conductor pipe is 

mechanically driven into the surface 

formations without any cement, and in 

other instances the conductor pipe 

consists merely of corrugated pipe and 

is cemented with construction cement. 

One of the roles of the surface casing, 

the first casing string set, is to protect 

the near-surface usable-quality waters. 

Because conductor casing is not 

designed to protect usable water zones, 

the CEL requirement does not apply. In 

addition, the surface casing would be 

adequately cemented inside the 

conductor pipe, thus protecting nearsurface zones. 

What is inadequate cement? 

Several commenters stated that 

section 3162.3–3(e)(2) (proposed section 

3162.3–3(e)(4)) regarding indications of 

inadequate cement should be modified. 

Commenters indicated that the 

inadequate cement job criteria listed 

were not good indicators of an 

inadequate cement job. The commenters 

did not offer any suggestions of what 

would be good indicator(s). The BLM 

did not revise the rule as a result of this 

comment. The provision regarding 

indicators of inadequate cement, at final 

section 3162.3–3(e)(2)(i), expressly 

includes the language ‘‘such as, but not 

limited to’’ to indicate that the 

subsequent list is not an exhaustive list 

of possible indications of inadequate 

cement. 

The BLM also received comments that 

this section should be revised to exempt 

cement fall back from being classified as 

an indication of inadequate cement. 

Commenters indicated that there should 

be a specific exception for those 

instances where the only remedy is to 

top-fill cement that has settled in the 

annulus after curing. The BLM agrees 

and has revised the rule as a result of 

these comments. Section 3162.3–3(e)(2) 

now addresses adequate cement for 

surface casing or intermediate and 

production casing separately. 

Additionally, the BLM believes that the 

fallback indicator for inadequate cement 

should incorporate a performance 

standard. Based on the BLM’s 

experience, 10 percent of surface casing 

setting depth or 200 feet, whichever is 

less, is the limit that routine ‘‘top-jobs’’ 

are successfully performed; therefore, 

the rule has been revised to incorporate 

this exception as a fall back indicator for 

inadequate cement. Appropriate 

remedial operations are to be conducted 

in either event; however, determination 

of the cement top via a CEL would not 

be required under this exception. 

Certifications 

Numerous commenters stated that the 

rule provisions dealing with selfcertification should be modified. The 

supplemental proposed rule proposed 

self-certification statements for remedial 

cement jobs, wellbore integrity, fluids 

used, and compliance with laws and 

regulations. 

Some commenters indicated that 

certifications are unnecessary and 

require the operator to certify the 

actions of third parties over whom they 

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7Hydraulic Fracturing Operations—Well 

Construction and Integrity Guidelines, API 

Guidance Document HF1 (1st ed., Oct. 2009). 

have no direct control; in addition, 

concern was expressed with the 

potential liability issues of certification 

for operations conducted by another 

party. The BLM did not make any 

changes to the rule as a result of these 

comments. By definition, in existing 

section 3160.0–5, the operator is the 

entity that is responsible for the 

operations conducted under the terms 

and conditions of the lease. As such, the 

BLM believes it is appropriate that the 

operator be responsible for all aspects of 

hydraulic fracturing operations, 

regardless of the party that conducts the 

work. The BLM will hold the operator 

responsible for all actions of third party 

contractors on a Federal or tribal lease. 

Requiring the operator to submit the 

certifications is appropriate and 

provides added assurance that hydraulic 

fracturing operations were conducted in 

compliance with the regulations. 

Some commenters objected to the 

requirement that the operator certify 

proper execution of remedial cement 

jobs, the mechanical integrity of casing, 

and legal compliance related to 

hydraulic fracturing fluids, among other 

issues. They asserted that it is 

impossible for the operator to have one 

individual who can certify all of those 

matters and said that the possibility of 

criminal enforcement is an 

unreasonable imposition. The BLM 

disagrees. The operator has always been 

responsible for everything that occurs 

on the permitted well site. See existing 

section 3100.5(a). If an operator uses 

one or more service contractors for 

specific tasks, the operator remains fully 

responsible for those operations. See 

existing section 3162.3(b). If the 

operator’s contractor, as its agent under 

existing section 3162.3(b), submits a 

certification, it is deemed to have come 

from the operator. Since 1948, the law 

has provided for criminal liability for 

certain false statements in public land 

matters, whether sworn or unsworn. 43 

U.S.C. 1212. The certification 

requirement underscores the importance 

of operators taking responsibility for 

reporting accurate information 

necessary to assure that hydraulic 

fracturing operations were properly 

conducted and is intended to ensure 

that contractor activities on the lease are 

properly overseen by the operator. The 

final rule is not revised in response to 

these comments. 

Other commenters were concerned 

that despite taking all prudent steps, 

implementing accepted industry 

standards, and complying with all 

regulatory requirements in the final 

rule, the operator could in good faith 

provide a certification that later in time 

is found invalid based on circumstances 

or facts unknown to the operator or that 

were out of his or her control. The BLM 

did not make any changes to the rule 

based on these comments. The BLM 

would take an operator’s diligence and 

good faith into consideration in 

exercising enforcement discretion where 

a certification was later shown to have 

been in error. 

Other commenters said that 

additional certifications should be 

required, including fracture propagation 

and the protection of usable water. The 

BLM did not make any changes to the 

rule as a result of these comments. The 

BLM believes that the subsequent report 

adequately details fracture design 

considerations, including fracture 

propagation. Additionally, usable water 

considerations are addressed at both the 

APD and hydraulic fracturing review 

stages. 

Cement Monitoring Report 

Several commenters suggested that 

the rule require the cement monitoring 

report in paragraph section 3162.3– 

3(e)(1) to be submitted to the BLM prior 

to commencing hydraulic fracturing 

operations. This would give BLM field 

offices the opportunity to review the 

report to ensure the cement job was 

adequate. The proposed rule would 

have given operators 30 days from the 

completion of hydraulic fracturing 

operations to submit the cement 

monitoring report. The BLM agrees with 

this comment and revised final section 

3162.3–3(e)(1) to require that the report 

be submitted at least 48 hours prior to 

commencing hydraulic fracturing 

operations. 

One commenter suggested that the 

cement contractor’s report should be 

acceptable to the BLM. The 

requirements of the cement report are 

detailed in section 3162.3–3(e)(1) of this 

rule. Any report meeting these 

requirements would be acceptable to the 

BLM, including a report submitted by 

the cement contractor as an agent of the 

operator. See 43 CFR 3162.3(b). No 

changes to the rule were made as a 

result of this comment. 

One commenter suggested that the 

cement monitoring report in section 

3162.3–3(e)(1) should be submitted to 

the BLM within 30 days of cementing, 

not within 30 days after completion of 

hydraulic fracturing operations as stated 

in the supplemental proposed rule. 

This, according to the commenter, 

would give the BLM adequate time to 

review the report prior to hydraulic 

fracturing. The rule is revised based on 

other comments to require the cement 

monitoring report at least 48 hours prior 

to hydraulic fracturing, which addresses 

the commenter’s concern. In addition, 

the BLM does not believe that operators 

would proceed to fracture a well if the 

monitoring report showed a failure to 

ensure isolation and protection of 

usable water, knowing that if the BLM 

discovered the failure, the operator 

would be subject to enforcement action. 

Section 3162.3–3(f) Mechanical 

Integrity Test 

This section requires the operator to 

conduct a Mechanical Integrity Test 

(MIT). The MIT required by this rule is 

a pressure test of the casing through 

which the hydraulic fracturing will 

occur or through the fracturing string (if 

used). Industry guidance and many state 

regulations are consistent with this 

requirement. The API’s guidance 7

clearly indicates the need for the MIT. 

The threshold of 30 minutes with no 

more than 10 percent loss of applied 

pressure is used by many states (TX, LA, 

CO, WY, and others). 

Industry guidance on hydraulic 

fracturing states that the operator should 

pressure test the production casing. 

‘‘Prior to perforating and hydraulic 

fracturing operations, the production 

casing should be pressure tested 

(commonly known as a casing pressure 

test). This test should be conducted at 

a pressure that will determine if the 

casing integrity is adequate to meet the 

well design and construction 

objectives.’’ (API Guidance Document 

HF1, First Edition, October 2009) This 

casing pressure test meets the intent of 

the MIT required by the rule. 

Two changes were made to the MIT 

requirements in the final rule. The 

reference to refracturing in the 

supplemental proposed rule is deleted 

because the final rule no longer makes 

any distinction between refracturing 

and fracturing. The requirement to only 

perform an MIT on vertical sections of 

the wellbore in the supplemental 

proposed rule is also deleted in the final 

rule. This change ensures that the entire 

length of casing or fracturing string, not 

just the vertical section, prior to the 

perforations or open-hole section of the 

well, is able to withstand the applied 

pressure and contain the hydraulic 

fracturing fluids. In addition, it was 

unclear to what the term vertical section 

would apply in a directionally drilled 

well. 

The BLM received numerous 

comments on performing a successful 

MIT prior to hydraulic fracturing. These 

comments ranged from concerns 

involving need, type wells, MIT 

reporting, well configurations, 

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terminology, test pressures and finally, 

alternative testing procedures. 

Several commenters stated that the 

MIT requirement in general is 

unnecessary and costly. Other 

commenters indicated that because 

MITs are already completed as a matter 

of industry practice prior to any 

pumping procedure, regulating such 

procedure is merely bureaucratic and 

serves no environmental protection. The 

BLM realizes that many operators 

perform MITs; however the BLM 

believes that ensuring casing integrity 

prior to hydraulic fracturing is essential 

and that the only way to verify the 

integrity of the casing is to require a test 

to the anticipated hydraulic fracturing 

pressure. An MIT conducted 

immediately preceding the hydraulic 

fracturing operation to the specified test 

pressure would suffice. No change was 

made to the rule as a result of these 

comments. 

Some commenters were concerned 

that an MIT would not be required on 

every well if the type well concept was 

adopted. As discussed, the proposed 

type well concept is not included in the 

final rule. Elimination of the type well 

concept clarifies any confusion 

regarding the requirement for an MIT for 

type wells. The final rule now requires 

that a successful MIT be performed on 

every well prior to hydraulic fracturing. 

The BLM believes that this is the only 

method that will ensure that each well 

to be hydraulically fractured 

demonstrates the appropriate structural 

capabilities to withstand the intended 

applied pressures. 

Some commenters said that the rule 

requiring MITs for refracturing should 

be modified. The commenters stated 

that the requirement to perform an MIT 

before refracturing operations is 

unjustified. The commenter suggested 

that the BLM should put a timing 

restriction on when an MIT must be 

performed when refracturing a well. As 

previously discussed, the final rule has 

eliminated the term ‘‘refracturing’’ in its 

entirety. An MIT will be required prior 

to the first hydraulic fracturing 

operation in any well, and prior to all 

subsequent hydraulic fracturing 

operations in that well. To ensure 

proper wellbore integrity for protection 

and isolation of the usable water, an 

MIT will be required to ensure that an 

existing well is properly bonded and 

sheathed to sustain high pressures 

during a hydraulic fracturing operation. 

The BLM did not revise the rule as a 

result of these comments. 

Other commenters recommended that 

the BLM require reporting the results of 

the MIT prior to hydraulic fracturing. 

The BLM does not believe that a 

requirement to report the results of the 

MIT prior to fracturing is necessary to 

ensure wellbore integrity. Final section 

3162.3–3(f) requires a successful MIT 

prior to hydraulic fracturing; therefore, 

if the MIT failed and the operator 

proceeded with hydraulic fracturing 

operations, the operator would be in 

violation of the rule and would be 

subject to enforcement actions. No 

revisions to the rule were made as a 

result of this comment. In addition, final 

section 3162.3–3(i)(8)(i) requires a 

certification to be signed by the operator 

that it had performed a successful MIT 

under section 3162.3–3(f). 

Some commenters recommended that 

the BLM clarify the requirement for 

conducting the MIT when the well 

configuration contains a pressureactuated valve or sleeve at the end of a 

lateral completion. The commenters 

expressed concern that pressure testing 

this valve or sleeve to maximum 

anticipated pressure will possibly open 

the valve or sleeve, causing the pressure 

test to fail the proposed standard of 30 

minutes with no more than a 10 percent 

pressure loss. The BLM also received 

comments urging modification to the 

MIT requirements for open-hole 

completions. The BLM appreciates the 

concerns expressed by the commenters. 

The BLM believes that ensuring casing 

integrity prior to hydraulic fracturing is 

essential and the best way to ensure the 

integrity of the casing is to test to the 

anticipated hydraulic fracturing 

pressure. No revisions to the rule were 

made as a result of these comments. 

Also, because this is a national rule, it 

cannot address all the possible wellbore 

configurations, and the BLM recognizes 

that certain wellbore configurations may 

require modifications to perform this 

test. Many wellbores will require the 

setting of packers, or other acceptable 

methods, to isolate existing, sensitive 

downhole components or open-hole 

completions. Operators are encouraged 

to anticipate these complications and 

provide details to the BLM’s authorized 

officers in their hydraulic fracturing 

APDs and NOIs. 

Several commenters requested 

clarification regarding at what point in 

the process should results of the MITs 

be submitted and for how long must the 

operator keep the results of the MIT. 

The final rule was not revised as a result 

of these comments; however, the rule 

was reorganized to better reflect the 

BLM’s intent. As required by final 

section 3162.3–3(i)(9), the MIT results 

are required to be submitted to the BLM 

authorized officer, via a subsequent 

report, within 30 days after the 

completion of the last stage of the 

hydraulic fracturing for each well. 

Existing section 3162.4–1(d) requires 

that the operator maintain all required 

records and reports, including MITs, for 

6 years from the date that it was 

generated. 

Some commenters said that the rule 

should be modified to change the term 

‘‘MIT’’ to ‘‘casing pressure test.’’ Other 

comments asked if the MIT was the 

same casing pressure test required by 

Onshore Order 2. The BLM did not 

make any changes to the rule as a result 

of these comments. The BLM believes 

that the term ‘‘Mechanical Integrity 

Test’’ is widely understood by industry, 

is used by many state regulatory 

agencies, and accurately describes the 

test. The MIT required by final section 

3162.3–3(f) is not equivalent to either 

the casing pressure test required by 

Onshore Order 2, section III.B.1.h., or 

the casing shoe pressure test as 

currently required by Onshore Order 2, 

section III.B.1.i. The MIT is a specific 

test conducted on a wellbore in its 

hydraulic fracturing configuration and 

to the maximum anticipated pressure 

for the hydraulic fracturing operation 

being contemplated. 

Some commenters suggested various 

alternative testing pressures or 

procedures to be used for the MIT. 

Commenters recommended lower 

pressures than the proposed rule 

provided or suggested that alternative 

methods, including ultrasonic imaging, 

could be utilized. Final section 3162.3– 

3(f) requires the operator to perform a 

successful MIT to not less than the 

maximum anticipated surface pressure 

that will be applied during the 

hydraulic fracturing process. This 

testing is necessary to help ensure the 

integrity of the wellbore during 

hydraulic fracturing operations. This 

test demonstrates that the casing 

provides sufficient structural strength to 

protect usable water and other 

subsurface resources during hydraulic 

fracturing operations. The BLM 

specifically chose the MIT over other 

alternative tools so that the test could be 

accomplished without requiring 

additional equipment, such as 

ultrasonic imaging tools. No revisions to 

the rule were made as a result of these 

comments. However, the BLM may 

consider a proposal by the operator to 

use alternative tools to an MIT. If such 

tools meet or exceed the objectives of 

performing an MIT, then the BLM may 

authorize an operator to use such tools 

as a variance to this requirement. 

Commenters suggested alternative 

MIT failure indicator levels. Section 

3162.3–3(f)(3) requires the well to hold 

the pressure for 30 minutes with no 

more than a 10 percent pressure loss. As 

previously pointed out, this test 

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confirms the mechanical integrity of the 

casing and is the same ‘‘failure’’ 

standard that the BLM established for 

drilling operations in Onshore Order 2, 

section III.B.h.; therefore, this language 

does not set a new standard in the 

BLM’s regulations. The MIT, together 

with the other requirements, 

demonstrate not only the wellbore’s 

structural competency, but that 

reasonable precautions have been taken 

to protect usable water and other 

subsurface resources during hydraulic 

fracturing operations. Some commenters 

also indicated that this requirement is 

duplicative of state requirements and 

therefore is unnecessary. The BLM 

acknowledges that although this 

requirement may be duplicative of some 

states’ requirements, not all of the states 

to which this final rule is applicable 

have the same requirements and, 

therefore, this standard is necessary to 

protect Federal and tribal lands. Many 

commenters expressed that the 

requirement is common industry 

practice and that they support the 

requirement. No revisions to the rule 

were made as a result of these 

comments. 

Section 3162.3–3(g) Monitoring During 

Hydraulic Fracturing Operations 

This section requires the operator to 

continuously monitor and record the 

annulus pressure at the bradenhead 

during the hydraulic fracturing 

operation. 

In the final rule, the BLM removed the 

term ‘‘refracturing’’ from the title of the 

section because the final rule no longer 

defines or uses the term ‘‘refracturing.’’ 

The final rule also clarifies that when 

pressures within the annulus increase 

by more than 500 psi, the operator must 

stop fracturing operations and 

determine the reasons for the increase. 

Prior to recommencing hydraulic 

fracturing operations, the operator must 

perform any remedial action required by 

the authorized officer and successfully 

perform an MIT required under 

paragraph (f) of the rule. The BLM 

believes that these actions are necessary 

in these cases to ensure that the 

integrity of a wellbore is confirmed 

through an MIT prior to recommencing 

hydraulic fracturing operations. 

One commenter believed that the 

requirements for the operators in section 

3162.3–3(g) of the supplemental 

proposed rule to continuously monitor 

and record annulus pressure at the 

bradenhead were too vague and wanted 

more specificity in the rule. The 

commenter also believed that the 

requirement was unnecessary. The 

commenter explained that operators 

already monitor pressures during 

hydraulic fracturing operations using 

sophisticated and expensive equipment. 

Another commenter said that the 

monitoring requirement could not be 

achieved because the bradenhead is not 

accessible. The BLM reviewed the 

language in the supplemental proposed 

rule and has determined that the 

language in this section is clear as 

written. In fact, the language in this 

section is very similar to the 

requirements in Colorado rule 341 

(Colorado Oil and Gas Conservation 

Commission, February, 2014, http://

cogcc.state.co.us/). Changes in pressure, 

while not necessarily caused by 

mechanical failure due to hydraulic 

fracturing, provide an indication that 

mechanical failure may have occurred. 

The BLM appreciates the fact that 

operators already monitor pressures 

during hydraulic fracturing using 

sophisticated equipment. However, as 

indicated by comments, not all 

hydraulic fracturing operations utilize 

the same equipment and therefore 

specific requirements are necessary. The 

BLM finds no merit in the comment that 

the bradenhead is not accessible. 

Common industry practice is to 

construct wells that allow bradenhead 

access. Many states, including Colorado, 

Wyoming, Montana, and North Dakota, 

require bradenhead monitoring during 

hydraulic fracturing, and API guidance, 

‘‘Hydraulic Fracturing Operations-Well 

Construction and Integrity Guidelines, 

First Edition, October 2009,’’ commonly 

known as HF1, recommends annular 

pressure monitoring during hydraulic 

fracturing. 

Other commenters recommended that 

the monitoring should continue on a 

daily basis for the first 30 days after 

hydraulic fracturing and then monthly 

for 5 years thereafter. The BLM 

disagrees with this comment. Upon 

completion of pumping the hydraulic 

fracturing fluids, the wellbore is no 

longer subject to the pump pressure. 

Therefore, continual monitoring for 

wellbore issues caused by the hydraulic 

fracturing operation is unnecessary. No 

revisions to the rule were made as a 

result of these comments. 

Some commenters suggested that the 

reporting requirements of pressure 

increases by more than 500 psi during 

hydraulic fracturing operations in the 

annulus during hydraulic fracturing 

under section 3162.3–3(g)(2) of the 

supplemental proposed rule is 

unnecessary because it duplicates state 

requirements. Another commenter 

asserted the need for a more 

comprehensive regulatory approach for 

hydraulic fracturing operations in state 

and tribal lands. The BLM 

acknowledges that some states have 

similar requirements, but not all states 

have the same requirements. Since this 

rule applies to all Federal and Indian 

minerals, this requirement is necessary. 

Even in states that do have a similar 

requirement, the BLM needs to know 

about the pressure increase so that the 

BLM can work closely with the operator 

to correct the issue and take the 

appropriate action. 

Another commenter recommended 

that in addition to the oral notification 

of a pressure increase, written notice 

should also be required. The BLM 

believes oral notification is sufficient in 

this situation. If warranted, the BLM 

may require additional documentation 

regarding the pressure increase and the 

corrective measures that were taken to 

abate the situation. 

One commenter recommended that 

the BLM adopt the language in the 

original proposed rule which required 

the operator to file a subsequent report 

of the corrective actions taken within 15 

days, instead of the language in the 

supplemental proposed rule which 

requires the submission of the 

subsequent report within 30 days of 

completion of the hydraulic fracturing 

operations. As stated earlier, the BLM 

will work closely with the operator 

following notification of the pressure 

increase. Since the BLM will be aware 

of the incident by the oral notification 

and will be involved with the corrective 

action from the start, the timing of 

submission of the subsequent report is 

not critical to the BLM. The 30-day 

requirement is consistent with all of the 

other documentation required to be 

included in the subsequent report. No 

revisions to the rule were made as a 

result of these comments. 

One comment made numerous 

suggestions about additional monitoring 

that should take place on producing 

wells. The suggestions include: 

• Submit monthly and annual 

production reports including volume of 

oil and gas to the BLM; 

• Monitor pressure of each well daily 

for the first 30 days of operation; 

• Maintain production and 

monitoring reports for 5 years; 

• Conduct periodic well tests to 

determine flow rate and pressure; 

• Maintain and test wellhead 

equipment over the life of the well; 

• Annually report casing pressures to 

the BLM and notify the BLM if 

pressures approach the design limits of 

the casing; 

• Install pressure relief valves, 

especially on high-pressure or highvolume wells; and 

• Monitor all wells for corrosion and 

potential hazards. 

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The BLM did not revise the rule as a 

result of these comments because these 

comments apply to producing wells 

whether or not they are hydraulically 

fractured. The BLM believes that the 

existing monitoring, maintenance, and 

reporting requirements for producing 

wells are adequate. See 43 CFR part 

3160, and http://www.blm.gov/mt/st/en/ 

prog/energy/oil_and_gas/operations/

orders.html. 

For example, operators of Federal and 

Indian wells already must report 

production to the Office of Natural 

Resource Revenue (ONRR). 

Furthermore, the supplemental notice of 

proposed rulemaking did not propose to 

amend the onshore orders or other 

operating regulations. 

Several commenters suggested that 

the rule require operators to notify the 

BLM if the annular pressure exceeds 80 

percent of the casing internal yield 

rating during hydraulic fracturing. Both 

the supplemental and the final rules 

require the operator to notify the BLM 

if the annular pressure exceeds 500 psi. 

The BLM determined that the standard 

for notifying the BLM should be an 

objective and easily measured 

parameter. The 500 psi limit can be 

detected by observing a pressure gauge. 

A standard based on casing yield ratings 

as the commenters suggested would be 

more difficult to detect and implement, 

especially if the person observing the 

gauge was not familiar with the weight, 

grade, and depth of the casing run, or 

the weight of the mud in the hole. In 

addition, as part of the BLM’s review of 

hydraulic fracturing applications, the 

engineer will ensure that a 500 psi 

increase in annular pressure will not 

jeopardize the integrity of the casing. No 

revisions to the rule were made as a 

result of this comment. 

Section 3162.3–3(h) Storage of 

Recovered Fluids 

This section requires operators to 

manage recovered fluids in rigid 

enclosed, covered, or netted and 

screened above-ground tanks. Those 

tanks may be vented, unless Federal, 

state or tribal law, as appropriate for the 

surface estate involved, require vapor 

recovery or closed-loop systems. The 

tanks must not exceed a 500 barrel (bbl) 

capacity unless approved in advance by 

the authorized officer. In certain very 

limited circumstances, the operator may 

apply for approval to use a lined pit. 

Tanks that are not enclosed will need 

to be covered, netted, or screened to 

exclude wildlife. This is not a new 

requirement. In 2012, the BLM issued 

an instructional memorandum to its 

authorized officers to assure that pits, 

tanks, and similar structures are netted 

or screened to prevent entrapment and 

mortality of wildlife. (See http://

www.blm.gov/wo/st/en/info/regulations/

Instruction_Memos_and_Bulletins/

national_instruction/2013/IM_2013- 

033.print.html.). These mitigation 

requirements are used to help prevent 

deaths of animals protected under the 

Migratory Bird Treaty Act and other 

laws. 

The supplemental proposed rule 

would have required that recovered 

fluids be stored in lined pits or tanks 

unless otherwise required by the BLM. 

The final rule incorporates two 

significant changes. First, the BLM 

decided not to distinguish flowback 

fluid from produced water. Instead, in 

the final rule the requirements for the 

storage of flowback fluid only apply to 

the interim period between the 

completion of hydraulic fracturing and 

the implementation of an approved plan 

for the disposal of produced water 

under Onshore Order 7. Fluids 

produced from the well during this 

period are referred to as ‘‘recovered 

fluid’’ in the final rule and the term 

‘‘flowback’’ is deleted from the rule. 

Second, instead of allowing lined pits or 

tanks, as proposed in the supplemental 

proposed rule, the final rule requires 

that all recovered fluids to be stored in 

above-ground tanks unless otherwise 

approved by the BLM in advance of 

generating recovered fluids. In addition, 

a list of minimum criteria for the 

approval of storage in lined pits is 

included in the final rule. 

Pits vs. Tanks 

In the supplemental proposed rule, 

the BLM asked for comments on 

whether flowback fluids should only be 

stored in closed tanks. The BLM 

received comments that both supported 

and objected to this proposal. 

Comments supporting a ‘‘tanks only’’ 

approach stated that the risk of impacts 

to air, water, and wildlife is too great, 

even if a pit is lined. Those commenters 

stated that lined pits are still subject to 

breaching, failure, and leaking. In 

addition, because pits are open to the 

atmosphere, fumes from the fluid in the 

pits can become airborne and cause 

health and environmental problems. 

The commenters also raised the 

possibility of wildlife getting into pits 

and dying or becoming ill from 

exposure to the chemical constituents in 

the fluids. Some of these comments 

suggested that flowback fluid should 

only be stored in ‘‘closed systems’’ that 

would not only use tanks, but the tanks 

would be vapor tight to eliminate the 

possibility of air contamination. 

Many of the comments objecting to a 

‘‘tanks only’’ approach raised the issue 

of increased cost if tanks or ‘‘closed 

systems’’ were required. Most of these 

comments preferred the flexibility of 

lined pits or tanks, depending on the 

location or the specific situation. For 

example, the extra cost of storing 

flowback fluid in tanks may have no 

benefits in remote areas where there are 

no water sources which could be 

contaminated and no human 

populations that could be affected by 

airborne contaminants. Some of the 

comments suggested that the rule could 

require geo-textile or composite liners or 

double-lined pits with leak detection 

systems in order to reduce the risks of 

leakage. Other commenters raised the 

concern of unintended consequences of 

requiring tanks, such as increased truck 

traffic. 

After reviewing these comments and 

comments relating to the definition of 

‘‘flowback,’’ the BLM decided to make 

a number of modifications to final 

section 3162.3–3(h). First, because the 

BLM is not differentiating ‘‘flow back’’ 

fluid from produced water, the 

requirements in paragraph (h) will only 

apply to the fluids recovered between 

the completion of hydraulic fracturing 

and the implementation of a plan for the 

disposal of produced water approved 

under BLM regulations, which currently 

are in Onshore Order 7. This will ensure 

that recovered fluids are stored and 

handled in a way that minimizes the 

risk of impacts to air, water, and 

wildlife during the interim period (up to 

90 days) while the BLM is reviewing the 

operator’s long-term plan for the 

disposal of produced water. When the 

information is available, the BLM highly 

encourages operators to submit their 

plans for long-term storage of recovered 

fluids with their APD or NOI for 

proposed hydraulic fracturing 

operations to allow the BLM to evaluate 

the various aspects of an operator’s 

development proposal under one review 

process, rather than multiple processes. 

Second, the BLM agrees with the 

comments stating that the storage of 

flowback, or recovered fluid in pits, 

poses a risk of impacts to air, water, and 

wildlife. Therefore, this rule requires 

storage of recovered fluids in rigid 

enclosed, covered, or netted and 

screened above-ground tanks during the 

interim period before the operator 

implements a BLM-approved plan for 

the disposal of produced water under its 

regulations (currently in Onshore Order 

7). The BLM believes that above-ground 

tanks, when compared to pits, are less 

prone to leaking, are safer for wildlife, 

and will have less air emissions. The 

BLM generally considers tanks as being 

constructed from a rigid material such 

as steel or fiberglass. The BLM realizes 

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8Link to the Final COGCC Policy: https://

cogcc.state.co.us/RR_Docs_new/Policies/

MLVTPolicyFinal20140613.pdf. 

that, if enclosed, tanks will still need to 

be vented to prevent the tanks from 

bursting or collapsing when filling or 

emptying the tanks and to compensate 

for changes in temperature. Venting will 

release some vapors into the 

atmosphere. Although a ‘‘closed loop’’ 

system would be approvable, we do not 

currently have an adequate basis to 

require such a system nationwide. 

However, the BLM supports states and 

tribes that require vapor-recovery or 

‘‘closed loop’’ systems. Also, from the 

BLM’s observations in the field, many 

operators already choose to use tanks in 

lieu of pits for temporary storage of 

recovered fluids to manage costs and 

timing of operations, and to control 

impacts to the environment and any 

resulting liability. 

Third, the BLM agrees with the 

comments asking for the flexibility to 

allow lined pits based on site-specific 

conditions, but believes such exceptions 

should be limited and rarely granted. As 

a result, final section 3162.3–3(h)(1) 

allows the BLM to approve the storage 

of recovered fluids in lined pits on a 

case-by-case basis and only if the 

applicant demonstrates that the use of 

an above-ground tank is infeasible for 

environmental or public health or safety 

reasons only and all of the listed criteria 

are met. In circumstances where use of 

above-ground tanks has concomitant 

impacts to the environment, public 

health, and safety, the rule allows BLM 

to exercise its discretion to approve 

lined pits, but only if they meet all of 

the listed criteria. These criteria include 

minimum distances from water sources, 

public places, and residences, as well as 

potential floodplain impacts. If 

approved, the lined pit would be 

required to be constructed and 

maintained in accordance with final 

section 3162.3–3(h)(2), which requires 

the pit to be properly located, lined with 

a durable, leak-proof synthetic material 

and equipped with a leak detection 

system. Onshore Order 7 already 

establishes a standard for leak detection 

systems when disposing of produced 

water into lined pits. The minimum 

distances found in this section are 

similar to requirements found in Title 

19, Chapter 15, Part 17 of the New 

Mexico Administrative Code. The BLM 

considers the criteria in this section as 

minimum requirements—if an operator 

proposes to store recovered fluid in a 

lined pit that does not meet one or more 

of these minimum requirements, the 

BLM would not approve the storage 

method. However, the BLM has the 

discretion to deny proposals to use 

lined pits that meet or exceed the 

minimum criteria, based on site-specific 

conditions. In no cases would the BLM 

allow the storage of recovered fluids in 

unlined pits. 

Moreover, in the BLM’s experience, 

the use of tanks in lieu of pits in highvolume operations limits potential 

environmental impacts, allows for 

quicker site preparation, reduces 

reclamation requirements, eliminates 

longer term environmental risk, reduces 

risks of spills or leaks, and increases 

safety. A tank can be removed in a day 

and there is no waiting required to 

recontour and seed the surface for 

reclamation purposes. The use of tanks 

for temporary storage of recovered fluids 

also provides the additional advantage 

of not requiring any long-term 

monitoring and mitigation. Pits also 

require periodic upkeep, monitoring, 

and fences. Several comments suggested 

that treatment and injection is the safest 

and most effective way to dispose of 

flowback fluids. The BLM did not revise 

the rule based on these comments 

because the ultimate disposal of 

recovered fluids is outside the scope of 

this rule, and, except for disposal on or 

in public lands, is outside of the BLM’s 

regulatory authority. 

In the BLM’s experience, most 

operators use rigid, truck- or trailermounted tanks for temporary storage of 

recovered fluids, and those tanks are 

usually no larger than 500 bbl capacity. 

Large open-topped tanks, often called 

‘‘semi-rigid,’’ can be susceptible to 

failures of seams or welds. Failure of a 

large-capacity tank containing recovered 

fluids would pose particular risks of 

harm to humans and wildlife because of 

the amount of fluid involved. Failures of 

large-capacity open-topped tanks have 

been documented. For example, 

between October 2011 and June 2013, 

there were five catastrophic failures of 

large-volume tanks reported to the 

Colorado Oil and Gas Conservation 

Commission (none of those tanks 

contained recovered fluids). Colorado 

has banned the storage of recovered 

fluids from such large-volume tanks.8

For these reasons, the rule provides that 

tanks used for temporary storage of 

recovered fluids must not exceed 500 

bbl capacity, unless approved in 

advance by the authorized officer. 

Flowback vs. Produced Water 

In the supplemental proposed rule, 

the BLM asked for comments on 

whether or not the rule should 

differentiate flowback fluids from 

produced water and, if so, how the two 

should be distinguished. Flowback 

fluids generally refer to the fluids 

recovered from the well immediately 

after hydraulic fracturing, presumably 

containing a high percentage of the 

fluids injected during hydraulic 

fracturing. Produced water is generally 

considered to be water from the 

hydrocarbon zone that is produced 

along with oil and gas. 

Onshore Order 7 establishes 

requirements for the handling and 

disposal of produced water. If this rule 

did not distinguish flowback fluid from 

produced water, then Onshore Order 7 

could be applied to all water produced 

from the well, including that water 

recovered from the well immediately 

after hydraulic fracturing. If this rule 

did distinguish flowback fluid from 

produced water, then unique handling, 

disposal, and reporting requirements 

could be imposed for the flowback fluid. 

The majority of comments received 

regarding this issue recommended that 

the rule not try to distinguish flowback 

fluid from produced water. The primary 

reasons given were: (1) There is no way 

to define the difference between the 

two; and (2) They are both potentially 

hazardous and should be treated in the 

same manner. A minority of comments 

recommended that the rule establish 

special handling, disposal, and 

reporting requirements for flowback 

fluid. However, no clear or enforceable 

means of making the distinction was 

given. Several comments suggested a 

time-based approach (e.g., flowback 

would end 10 days after the completion 

of hydraulic fracturing), while others 

suggested that the flowback period end 

when oil and gas production begins. 

The BLM considered numerous 

different criteria on which to 

differentiate flowback fluid from 

produced water, including all the 

methods suggested in the comments. 

The BLM decided that any method of 

differentiation would be either arbitrary 

(e.g., 10 days after the completion of 

hydraulic fracturing) or difficult to 

implement. For example, several states 

define flowback fluid as the fluid 

recovered prior to the production of oil 

and gas. However, the time at which the 

production of oil and gas begins is not 

always clear, therefore making this 

alternative difficult to apply. Often, 

some quantity of oil or gas is produced 

from the well almost immediately after 

hydraulic fracturing. In other cases, it 

might be days or weeks later. 

‘‘Production’’ could mean whenever 

measureable amounts of oil and gas are 

detected in the recovered fluid or it 

could mean when oil and gas is 

produced in marketable quantities. Any 

method based on the quantity or quality 

of oil and gas production would need to 

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16164 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

be measured and tracked. Additionally, 

it is unlikely that the chemical 

constituency or toxicity of the recovered 

fluid would change significantly once 

oil and gas was detected; therefore, 

there would be no practical reason to 

make such a distinction. 

Ultimately, the BLM decided not to 

make a distinction between flowback 

fluid and produced water and all 

references to the term ‘‘flowback’’ were 

removed in the final rule (sections 

3162.3–3(d)(5), (i)(6), and (i)(7)). 

Instead, the term ‘‘recovered fluid’’ is 

used in the final rule for all fluids 

coming from the well after a hydraulic 

fracturing operation is complete. Also 

Onshore Order 7 generally applies to all 

recovered fluids, including those fluids 

recovered immediately after hydraulic 

fracturing. However, under Onshore 

Order 7, section III.A., an operator has 

permission to temporarily dispose of 

produced water from newly completed 

wells for up to 90 days, until an 

application for the disposal of produced 

water is approved by the authorized 

officer. This 90-day interim period is 

typically when the highest percentage of 

hydraulic fracturing fluid is recovered. 

The BLM determined that special 

handling provisions are necessary for 

fluids recovered during this interim 

period after hydraulic fracturing and 

revised section 3162.3–3(h) of the final 

rule as a result (see the discussion of 

pits versus tanks under section 3162.3– 

3(h)). 

The BLM also revised the provision 

for reporting the volume of fluid 

recovered during flowback, swabbing, or 

recovery from production vessels in 

final section 3162.3–3(i)(6). Instead of 

reporting volumes of ‘‘flowback’’ in the 

subsequent report for an undefined 

period of time, the BLM determined that 

the ultimate goal is to have a complete 

record of all volumes recovered from a 

well, regardless of how it is defined or 

when it is recovered. ONRR requires 

operators to report the monthly volume 

of all fluids (oil, gas, and water) 

produced from wells on the Oil and Gas 

Operations Report, Part A (OGOR A). 

However, some operators do not start 

reporting on OGOR A until royaltybearing quantities of oil and gas are 

produced, thereby leaving a potential 

gap in the reporting of recovered fluids. 

To fill this gap, paragraph (i)(6) in the 

final rule requires operators to report 

the volume of fluid recovered between 

the completion of hydraulic fracturing 

and the start of reporting on OGOR A. 

Because the subsequent report is due 30 

days after the completion of the last 

stage of hydraulic fracturing, there may 

be situations where the subsequent 

report is filed prior to the start of 

reporting on OGOR A. In these cases, 

the operator would have to file an 

amended subsequent report showing the 

total volume of fluid recovered prior to 

the start of reporting on OGOR A. 

Refer to Figures A and B for an 

example of how the BLM will 

implement the provisions of this rule. 

Both figures show the flow rate of fluid 

recovered after hydraulic fracturing over 

some time period. Typically, the initial 

flow rate is high and declines over time 

as the excess pressure caused by 

hydraulic fracturing is relieved. The 

area under the flow-rate curve 

represents the volume of fluid recovered 

over a given time period. In Figure A, 

the operator begins reporting produced 

volumes on OGOR A 10 days after the 

completion of hydraulic fracturing and 

submits its subsequent report 20 days 

after the completion of hydraulic 

fracturing. Because reporting of 

recovered volumes on OGOR A 

precedes submittal of the subsequent 

report, only that volume recovered 

between the completion of hydraulic 

fracturing operations and the start of 

reporting produced fluids on OGOR A 

would be reported on the subsequent 

report—12,000 bbl in this example. The 

additional 5,000 bbl recovered before 

the submittal of the subsequent report 

will be captured by the volumes 

reported on OGOR A, thereby providing 

a continuous record of the volume of 

fluid recovered for the life of the well. 

In Figure B, the subsequent report is 

submitted on its due date (30 days after 

the completion of hydraulic fracturing), 

but reporting of produced fluids on 

OGOR A does not occur until 40 days 

after the completion of hydraulic 

fracturing. In this example, the operator 

would have to submit a supplemental 

subsequent report showing the total 

volume of 24,000 bbl recovered between 

the completion of hydraulic fracturing 

and the start of reporting on OGOR A. 

BILLING CODE 4310–84–P 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16165 

BILLING CODE 4310–84–C 


mstockstill on DSK4VPTVN1PROD with RULES2ER26MR15.000</GPH>

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40 
16166 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

Other Flowback Requirements 

Several comments suggested that the 

BLM require that flowback fluid be 

tested prior to disposal. The BLM did 

not revise the rule as a result of this 

comment because disposal of recovered 

fluids is generally done off-site and 

under the authority of other agencies 

such as the EPA (for underground 

injection). Disposal on Federal or Indian 

land would be covered under Onshore 

Order 7. 

One commenter suggested that the 

BLM create a manifest system to assure 

proper disposal of recovered fluids. 

While the commenter did not expound 

on what was meant by a ‘‘manifest 

system,’’ the BLM assumes it to mean a 

system of formal documented custody 

transfer ensuring that all flowback fluid 

removed from the site arrives at its 

destination (a disposal facility). Onshore 

Order 7 already requires the operator to 

submit a copy of the disposal facility’s 

permit, and a right-of-way authorization 

if the wastewater would travel over 

Federal or Indian lands off of the lease. 

Other agencies regulate the transport 

and disposal of chemical wastes, and 

this rule does not interfere with those 

regulatory programs. 

One comment suggested that the BLM 

should get rid of the Onshore Order 7 

provision that allows the disposal of pit 

liquids through evaporation. No 

revisions to the rule were made as a 

result of this comment because it cannot 

be addressed at this final rule stage, but 

the BLM will evaluate and consider 

options for updating requirements 

under all of its existing Onshore Orders. 

This rule sets standards for the handling 

of recovered fluid until a disposal plan 

is approved by the BLM under Onshore 

Order 7. This rule does not amend 

Onshore Order 7. 

Several commenters suggested that 

the rule should require the monitoring 

of constituents of flowback fluid. The 

BLM did not incorporate this suggestion 

because the goal of the rule is to contain 

the recovered fluids regardless of their 

chemical constituents. Disposal 

facilities often require an analysis of the 

fluid to be disposed; however, that is 

outside the scope of this rule. 

Section 3162.3–3(i) Subsequent Report 

This section lists information that the 

operator must submit to the BLM after 

the completion of a hydraulic fracturing 

operation and requires a disclosure of 

the chemicals used during the operation 

to FracFocus, the BLM, or another 

database that the BLM specifies. 

The BLM strongly encourages 

operators to submit the chemical 

disclosure data through the FracFocus 

database. If data is submitted directly to 

the BLM, the BLM will upload it to 

Fracfocus.org. This will meet the goals 

and requirements of the rule most 

effectively by providing a direct public 

disclosure of the chemical additives 

used in the hydraulic fracturing 

operation. If the BLM finds that 

operators are avoiding use of FracFocus 

without a justification, such as 

temporary problems with the FracFocus 

site, the BLM will consider requiring a 

filing fee for chemical disclosure data 

submitted directly to the BLM. 

Numerous changes are made to this 

section of the final rule. In the 

supplemental proposed rule, the 30-day 

time period for submitting the 

subsequent report would have begun 

when hydraulic fracturing operations 

were complete. In the final rule, the 

start of the time period begins after the 

last stage of hydraulic fracturing 

operations on each well is complete. 

This change is to clarify that in a multistage hydraulic fracturing operation, the 

operation is not complete until the last 

stage of hydraulic fracturing on each 

well is complete. 

In section 3162.3–3(i)(1), the final rule 

clarifies that a description of the base 

fluid and each chemical added to the 

hydraulic fracturing fluid must be 

reported, instead of each chemical used. 

The BLM made this change to clarify 

that operators do not have to report 

chemicals that are found in the water 

used as a base fluid, whether taken from 

surface or groundwater, or reuse or 

recycled water. The word ‘‘description’’ 

is added for clarity. 

The downhole information in section 

3162.3–3(i)(2) of the supplemental 

proposed rule is moved to a new section 

(i)(5) of the final rule for clarity and to 

be consistent with the informational 

requirement of section (d)(3). Section 

(i)(2) of the final rule is now specific to 

water sources and section (i)(5) is 

specific to downhole information. 

The pressure information in section 

3162.3–3(i)(3) of the supplemental 

proposed rule is changed in the final 

rule to clarify that the maximum surface 

pressure at the end of each stage is 

required. The supplemental proposed 

rule would have required the ‘‘actual 

surface pressure,’’ which could be 

ambiguous. The maximum surface 

pressure is needed for the BLM to 

ensure that the pressure used in the 

MIT, as required in section 3162.3–3(f) 

of the final rule, was not exceeded. 

Section 3162.3–3(i)(6) of the final rule 

redefines the period over which the 

volume of recovered fluids must be 

given in the subsequent report. In the 

supplemental proposed rule (section 

(i)(5)(i)) the volume of fluid to be 

included in the subsequent report was 

the amount recovered during flowback, 

swabbing, or recovery from production 

vessels. However, the supplemental 

proposed rule did not define the 

flowback period, or the period over 

which fluid recovery from swabbing or 

recovery from production vessels would 

have to be reported. The BLM 

determined that the goal of reporting 

recovered fluids is to have a complete 

history of everything that comes out of 

the well, regardless of how it is defined. 

Once an oil and gas well begins 

producing oil and gas, the monthly 

volumes of gas, oil, and water produced 

from each well must be reported on the 

OGOR A under 30 CFR 1210.102(a). 

Therefore, the only additional volumes 

that are needed to provide a complete 

history of fluids produced after 

hydraulic fracturing is the water 

produced immediately after hydraulic 

fracturing, but prior to the production of 

oil and gas that would trigger reporting 

on the OGOR A. If reporting on OGOR 

A does not start for more than 30 days 

after hydraulic fracturing—the 

timeframe in which the subsequent 

report is due—an amended subsequent 

report would have to be filed when 

OGOR A reporting started, showing the 

total volume of fluid produced since the 

completion of hydraulic fracturing. 

Section 3162.3–3(i)(7) of the final rule 

(section 3162.3–3(i)(5) of the 

supplemental proposed rule) is revised 

to apply only to the handling and 

disposal of fluids recovered between the 

completion of hydraulic fracturing 

operations and the approval of a plan 

for the disposal of produced water 

under Onshore Order 7. The 

supplemental proposed rule would have 

required information on the handling 

and disposal of recovered fluids, but did 

not define what constituted ‘‘recovered 

fluids.’’ In addition, the examples of 

handling and disposal methods are 

revised to coincide with the information 

requirements in the hydraulic fracturing 

application in section (d)(5). 

Section 3162.3–3(i)(7)(i) in the 

supplemental proposed rule would have 

required that the operator to certify that 

wellbore integrity was maintained 

under section (b) of the rule. Section 

3162.3–3(i)(8)(i) of the final rule is 

reworded so that it is clear that the 

certification refers to compliance with 

paragraphs (b), (e), (f), (g), and (h) of this 

rule. 

Section 3162.3–3(i)(9) of the final rule 

(section 3162.3–3(i)(8) of the 

supplemental proposed rule) is revised 

to eliminate the need to submit well 

logs and records of adequate cement 

(including CELs) under this section 

because the operator must already 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16167 

submit these under other sections of this 

rule and with the BLM Well Completion 

or Recompletion Report and Log (Form 

3160–4). 

Subsequent Report Fracture Data 

Several commenters were concerned 

that the specific fracture dimensions 

data required by this section (fracture 

length, height, and direction) could only 

be obtained through fracture modeling 

and requested that the BLM allow the 

use of fracture data gathered and 

modeled for similar wells, as opposed to 

requiring new modeling for every well. 

The BLM did not make any changes as 

a result of these comments. As provided 

by this section, fracture length, height 

and direction data can be actual, 

estimated, or calculated. The BLM is 

anticipating only hydraulic fracturing 

design estimates, and that hydraulic 

fracturing modeling is not required to 

meet this requirement. These data are 

obtained by some operators during the 

fracturing operation using microseismic 

fracture mapping, a diagnostic 

technique that measures created 

hydraulic fracture dimensions and their 

azimuth. The purpose of fracture data is 

to avoid potential interconnectivity 

between fractured pathways and either 

existing wellbores, i.e., so called ‘‘frack 

hits,’’ or zones containing usable water. 

Several comments suggested that the 

subsequent report compare the actual 

fracture dimensions with those 

estimated in the NOI. The BLM did not 

make any changes to the rule in 

response to these comments because the 

only method of verifying actual fracture 

dimensions is with a microseismic 

array, which the BLM is not requiring. 

The BLM believes that for the purpose 

of protecting ground water and 

identifying potential ‘‘frack hits,’’ 

estimated fracture dimensions are 

adequate. The estimated fracture 

dimensions are based on actual volume 

and pressure used during the hydraulic 

fracturing operation, and knowledge of 

the perforated string and the geology. 

Timeframe for Submittal 

Several commenters stated that the 

BLM should allow 60 days after 

completion of hydraulic fracturing 

operations for submitting the 

completion reports required under 

section 3162.3–3(i). Some commenters 

added that it takes the operator some 

time after the completion of operations 

to gather the information from their 

service contractors and to then compile 

the report accurately prior to 

submission. One commenter also 

indicated that for consistency with 

existing chemical disclosure reporting 

requirements of a couple of states 

(Colorado and North Dakota), the 

timeframe for submittal should be 

modified to 60 days. Another 

commenter suggested that the 

information could be submitted in an 

annual report. The BLM requirement to 

submit completion reports within 30 

days after completion is consistent with 

the BLM’s existing requirements under 

Onshore Order 1, section IV.e. Given 

experience with industry submission of 

information to the BLM, 30 days has 

been demonstrated to be an acceptable 

timeframe for accurate submissions. The 

BLM did not make any changes as a 

result of these comments. 

‘‘Fluid’’ Ambiguity 

One commenter suggested that the 

word ‘‘fluid,’’ as it is used in the rule 

to provide an estimated volume of fluid 

in the initial submission of hydraulic 

fracturing proposal under section 

3162.3–3(d)(4)(i) and for reporting the 

volume of fluid recovered under section 

3162.3–3(i)(6), is ambiguous. The 

commenter recommended that the BLM 

require reporting of the total volume of 

‘‘hydraulic fracturing fluid,’’ including 

gas, used or injected into the well, 

stated in gallons or other appropriate 

volumetric units of measurement. The 

BLM recognizes that a fluid includes 

both liquids and gases and any device 

employed to measure liquid volume 

would also measure any suspended or 

dissolved solids in the liquid. The BLM 

has defined the term ‘‘hydraulic 

fracturing fluid’’ in section 3160.0–5 in 

this rule. This should provide the 

needed clarity. Therefore, under this 

rule, the word ‘‘fluid’’ includes the 

liquid or gas, and any associated solids 

used in hydraulic fracturing, including 

constituents such as water, chemicals, 

and proppants. The BLM did not revise 

the rule based on this comment because 

the wording in the supplemental and 

final rules addresses the commenter’s 

concern. 

Third-Party Certification and Reporting 

One commenter stated that the term 

‘‘wellbore integrity,’’ as used in section 

3162.3–3(i)(7)(i) of the supplemental 

proposed rule is vague and undefined. 

The BLM agrees with that comment and 

has deleted the separate reference to 

‘‘wellbore integrity’’ in the final rule, 

which is now designated section 

3162.3–3(i)(8)(i). 

One commenter stated that the BLM 

should remove the requirement to 

certify wellbore integrity that crossreferences to usable water zonal 

isolation. The commenter states that 

section 3162.3–3(i)(7)(i) of the 

supplemental proposed rule would 

require that operators certify that well 

integrity was maintained prior to and 

throughout the hydraulic fracturing 

operation, as required by section 

3162.3–3(b). Section 3162.3–3(b) 

directly refers to the performance 

standard in section 3162.5–2(d) on 

isolation of all usable water. The 

commenter stated that isolation of 

useable water does not ensure wellbore 

integrity. The BLM agrees. This section 

of the final rule, which is now 

designated section 3162.3–3(i)(8)(i), has 

been rewritten to require the operator to 

certify that the operator complied with 

the requirements in paragraphs (b), (e), 

(f), (g), and (h) of the section. 

Another commenter said that 

operators should not be required to 

certify that isolation of usable water and 

mineral zones was achieved, and should 

only be required to use best efforts to 

isolate those zones, because isolation 

cannot be measured directly, but only 

inferred. The final rule is not revised in 

response to that comment. Isolation of 

zones of usable water or minerals is 

shown or inferred by data indicating 

that hydraulic fracturing fluids, 

recovered fluids, or oil and gas have not 

been lost from the wellbore in or around 

those zones. It is appropriate to require 

operators to review the reasonably 

available data concerning their 

operations and to certify that the data 

indicate that zonal isolation was 

achieved. 

A commenter was critical of the 

certification requirement, arguing that it 

added nothing because operators are 

required to comply with all applicable 

regulations, and that terms such as 

‘‘treatment fluid’’ and ‘‘wellbore 

integrity’’ are ambiguous. The 

commenter stated that an operator could 

in good faith believe that its certification 

was valid, but later it could be proved 

that there was an undiscovered 

problem. Although the BLM agrees that 

operators must comply with all 

applicable regulations, the BLM 

disagrees with the commenter’s 

conclusions. The term ‘‘treatment fluid’’ 

is not used in the regulations. The 

reference to wellbore integrity has been 

deleted. The function of the selfcertification is to require operators to 

conduct a good-faith review of the 

construction and operational data for 

any indication of problems. Certification 

of compliance with the requirements in 

paragraphs (b), (e), (f), (g), and (h) of the 

section is appropriate. 

A commenter said that the 

requirement for an operator to certify its 

compliance with applicable law for 

operations on an Indian reservation is 

unnecessary and could result in 

‘‘serious litigation.’’ The BLM disagrees. 

An operator on an Indian reservation is 

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responsible for knowing and complying 

with the applicable tribal and Federal 

law, just as an operator on non-tribal 

lands is responsible for knowing and 

complying with applicable state, local, 

and Federal law. The certification is an 

appropriate requirement in exercise of 

the Secretary’s trust responsibilities to 

assure that the operator has reviewed 

and verified its own compliance with 

tribal law. A certificate signed in good 

faith and following reasonable efforts to 

verify compliance would not increase 

any risk of litigation. 

One commenter recommended that 

the rule model its reporting and 

certification requirements (final section 

3162.3–3(i)(1) and (i)(8), respectively) 

on the Colorado Oil and Gas 

Conservation Commission (COGCC) 

Rule 205 and 205A because these rules 

strike a balance between reporting 

obligations of operators versus service 

companies. Rule 205A is specific to 

hydraulic fracturing and is most 

relevant to this rule. The BLM did not 

revise the rule as a result of these 

comments. The reporting requirements 

under 3162.3–3(i)(1) and Rule 205A, 

paragraph b, are very similar. Both 

require the disclosure of the hydraulic 

fracturing operations, including the well 

name, the total volume of water used, 

and the types and amounts of chemicals 

used in the operation (with exceptions 

for trade secrets). Both also require that 

the information be submitted by the 

operator (Rule 205A.b(2)). The Colorado 

rule requires vendors and service 

companies to provide water volume and 

chemical data to the operator; however, 

the operator is ultimately responsible 

for submitting the information to 

COGCC. In this respect, this rule is 

consistent with the Colorado rule. 

Section 3162.3–3(i)(8) in the final rule 

requires the operator to certify that it 

complied with paragraphs (b), (e), (f), 

(g), and (h) of the rule, and that the 

hydraulic fracturing fluid constituents 

comply with all applicable Federal, 

tribal, state, and local laws, rules, and 

regulations. There is no corollary 

requirement in the Colorado rule. The 

BLM primarily has authority over the 

parties who hold or operate the lease— 

the lease being the instrument through 

which the BLM exercises its authority 

over the lessee or operator. No changes 

to the rule were made as a result of this 

comment. 

One commenter said that the rule 

should be revised to improve the 

readability of sections 3162.3–3(i)(8)(ii) 

and (iii), which contain the phrase ‘‘the 

hydraulic fracturing fluid used 

complied . . . .’’ The commenter 

indicated that this phrasing makes no 

sense linguistically since hydraulic 

fracturing fluid does not comply, the 

operator complies. The BLM did not 

revise the rule as a result of these 

comments. The lead-in section for this 

certification section of the rule, now 

designated as section 3162.3–3(i)(8), 

clearly indicates that the certification 

signed by the operator contains the 

information that the hydraulic 

fracturing fluids used complies with all 

applicable permitting and notice 

requirements. 

FracFocus 

Some of the commenters noted that 

reporting requirements of the rule 

would reduce duplication of effort for 

the operators. They supported the 

provision in the rule that allows 

operators in states that require 

disclosure on FracFocus to meet both 

the state and BLM requirements through 

a single submission to FracFocus. The 

BLM agrees with these comments and 

did not make any changes to the rule. 

Other commenters were critical of 

FracFocus for not being user-friendly 

and for not allowing republication or 

linking with other databases. The BLM 

has been in discussions with the GWPC, 

which is responsible for the FracFocus 

database, to address some of these 

concerns. As of June 2013, the 

FracFocus database was upgraded to 

FracFocus 2.0. Their latest upgrades are 

explained on their Web site under 

‘‘Frequently Asked Questions’’ at 

www.fracfocus.org/faq. The BLM is in 

continued discussion with the GWPC 

and expects further progress and 

improvement of the site to ensure an 

effective chemical disclosure registry for 

the hydraulic fracture fluids. The BLM 

did not make any changes to the rule as 

a result of these comments. 

Some commenters suggested that 

additional information, such as the 

APD, well status, compliance, volume of 

fluid recovered, and complaint process, 

should be reported through the 

FracFocus submission. While some of 

this information is available through the 

BLM, FracFocus only publishes 

information related to disclosure of 

chemicals used in hydraulic fracturing 

fluids. The BLM did not revise the rule 

as a result of this comment. 

Some commenters were critical of 

FracFocus because of the unknown 

future condition and long-term 

reliability of this organization in hosting 

and retaining the data. A few 

commenters expressed concern about 

future funding, access, and data backup 

issues of FracFocus. Other commenters 

suggested that the disclosure registry 

should be searchable across forms and 

allow for meaningful cross-tabulation of 

search results. One of the commenters 

specified that each of the disclosure 

submissions should have a date stamp 

showing the actual date of submission 

to the database and validate/reject the 

correct/incorrect CAS Registry Numbers 

of the disclosed chemicals/ingredients 

when submitted. Another commenter 

suggested that the BLM should develop 

a new public disclosure platform 

tailored to the agency needs. The BLM 

considered these comments as valuable 

suggestions and will continue to work to 

improve any platform used for public 

disclosure. However, it did not make 

any changes in the rule because of these 

comments. 

The BLM has reviewed the Secretary 

of Energy Advisory Board’s FracFocus 

2.0 Task Force Report, dated March 28, 

2014, and its concerns and 

recommendations for FracFocus 

improvements as cited earlier in the 

preamble. Key issues raised include: 

The ability to search and generate 

information by chemical, well, 

company, and geography; quality 

control of data; and the capacity to 

handle large volumes of data. The BLM 

is committed to working with the DOE 

and FracFocus to ensure these issues are 

addressed so that public information 

gathered as a result of this rule is of high 

quality, accessible, and usable. As 

mentioned earlier, the GWPC and 

IOGCC, joint venture partners in the 

FracFocus initiative, announced the 

release of several improvements to 

FracFocus’ system functionality. The 

new features are designed to reduce the 

number of human errors in disclosures, 

expand the public’s ability to search 

records, provide public extraction of 

data in a ‘‘machine readable’’ format, 

update educational information on 

chemical use, environmental impacts 

from oil and gas production, and 

potential environmental impacts. The 

new self-checking features in the system 

will help companies detect and correct 

possible errors before disclosures are 

submitted. This feature will detect 

errors verifying that CAS numbers meet 

the proper format. These improvements 

to the system will address many of these 

concerns. 

Many commenters addressed the use 

of the FracFocus database and Web site. 

Some commenters supported the BLM’s 

proposal to allow submission of data 

through FracFocus. Other commenters, 

however, were critical of the proposal. 

Some commenters were concerned that 

the ownership of the data on FracFocus 

and the applicability of public 

disclosure laws, such as the Federal 

Freedom of Information Act (FOIA), are 

unknown. The Federal FOIA does not 

apply to FracFocus, because it is 

operated by the GWPC, which is not an 

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agency of the Federal Government. 

However, information on FracFocus 

concerning Federal or tribal wells is 

public information. 

A commenter suggested that the BLM 

adopt a procedure used in Texas that 

requires operators to submit to the state 

commission a copy of the information 

that they upload to FracFocus. Under 

this final rule, submission of the 

required information through FracFocus 

is optional; an operator may instead 

submit it directly to the BLM, and the 

BLM will upload it to FracFocus. The 

BLM’s intent, however, is to reduce the 

paperwork burden on operators by 

allowing them to submit information 

through FracFocus, if they so choose. 

Thus, in states that require submission 

on FracFocus, there would be no 

additional burden of complying with 

this requirement of the rule. 

Some commenters said that using 

FracFocus would violate an Executive 

Order requiring new government 

information to be available to the public 

in open, machine-readable formats, and 

the implementing guidance from the 

Office of Management and Budget. See 

Executive Order 13642, 78 FR 93 (2013), 

and Memorandum for the Heads of 

Executive Departments and Agencies, 

M–13–13 (OMB 2013). That Executive 

Order provides, in pertinent part, that 

the policy of the Executive Branch is 

that new and modernized Government 

information resources must be open and 

machine readable. The order is subject 

to several conditions, including 

available appropriations. 

That Executive Order does not 

prohibit the BLM from allowing 

operators to submit information through 

FracFocus. The BLM believes that 

FracFocus is the quickest, most costeffective way to make the information 

public. Working with FracFocus to meet 

the policy goals of the Executive Order, 

including machine-readable formats, 

will be more prompt and will use 

taxpayer dollars more efficiently than 

would the BLM creating and managing 

its own database solely for chemical 

disclosures. 

A commenter was concerned that 

using FracFocus could cause a conflict 

of interest because the GWPC is a trade 

association for the oil and gas industry. 

The BLM disagrees with this comment. 

The members of GWPC are the state 

agencies (www.gwpc.org/state-agencies) 

that protect and regulate ground water 

resources. They do not have a conflict 

of interest in operating FracFocus to 

serve as vehicle for operators to submit 

data to the BLM, or in making that 

information available to the public. 

A commenter said that using 

FracFocus would fail to meet minimum 

standards for managing government 

records. The commenter misconstrues 

the role of FracFocus. FracFocus will 

not be the official repository of the 

chemical information required by the 

rule. Whether an operator submits 

information to BLM directly or through 

FracFocus, the BLM will keep the 

information in its records. The 

information will also be available on 

FracFocus for the benefit of the public 

and state and tribal agencies. 

A commenter raised an issue of 

implementation and enforcement—that 

because FracFocus does not show the 

date that information is uploaded, it 

will be difficult for the BLM to know if 

the information was submitted within 

the time period required by the rule. 

The BLM will closely monitor 

FracFocus to ensure that operators 

submit information in a timely manner 

consistent with these regulations. The 

BLM will be working with the GWPC to 

improve the ability of FracFocus to meet 

the BLM’s needs and of operators on 

Federal or tribal lands. The final rule is 

not revised in response to those 

comments. 

Report Route Changes 

One commenter expressed concern 

that operators may change their access 

route and transportation methods for 

water used in fracturing wells after the 

initial approval. The commenter 

suggested that operators be required to 

report any changes in approved access 

routes and transportation methods. 

Although not explicitly stated, operators 

are required to follow the approved plan 

along with any conditions of approval. 

This requirement includes using the 

approved access route and 

transportation method. Any change to 

the approved plan requires the BLM’s 

approval. The Sundry Notice form itself 

addresses a change of plans. If the 

operator has a need to change the access 

route or transportation methods for 

water, they must file a change of plans. 

If the operator does not follow the 

approved plan along with any 

conditions of approval, the operator 

would be in noncompliance with the 

approval. The BLM would then take 

enforcement actions under 43 CFR part 

3163. No revisions to the rule were 

made as a result of this comment. 

Need for a Subsequent Report 

Some commenters stated the 

information required to be submitted to 

the authorized officer within 30 days 

after the completion of the last stage of 

hydraulic fracturing operations under 

section 3162.3–3(i), is redundant, 

unnecessary, and burdensome. The 

commenters stated that much of the 

information is provided in the NOI and 

some of the information is already 

required with the completion report. 

The information in the application and 

the information in the subsequent report 

serve different purposes. The 

information in the application allows 

the BLM to analyze the proposed 

operations to ensure that there will not 

be any unnecessary or undue 

degradation of public lands or breach of 

trust on Indian lands, and to develop 

any necessary mitigation to protect 

resources. The purpose of the 

subsequent report is to provide 

information on what was done and how 

it was done, as compared to how it was 

planned. Some information, such as the 

results of the MIT and the cement 

operations monitoring report, are not 

included in the APD or NOI, and can 

only be submitted after the operations 

are complete. The information included 

with the subsequent report also differs 

from the information required with the 

well completion report. Examples 

include the results of the MIT and the 

operator certification that it complied 

with paragraphs (b), (e), (f), (g), and (h) 

of the rule prior to and throughout the 

hydraulic fracturing operation. 

However, final section 3162.3–3(i)(9) is 

revised in response to comments 

pointing out that the proposed 

requirement to submit well logs and 

records of adequate cement duplicates a 

requirement in the well completion 

report. 

Fluid Volume Data 

One commenter requested that the 

total volume of fluid injected during a 

hydraulic fracturing operation should be 

reported. Another commenter requested 

further subcategorization of water 

volumes, such as surface, subsurface, 

and recycled water. The BLM did not 

revise the rule as a result of these 

comments. During a water-based 

hydraulic fracturing operation, water 

and proppant generally make up 

approximately 98–99 percent of the 

fluid injected during a fracturing 

operation and other additives, such as 

friction reducers, surfactants, gelling 

agents, and scale inhibitors make up the 

remaining, usually about 1–2 percent. 

The difference between total fluid used 

and volume of water used is 

insignificant from a volumetric 

perspective. Other commenters were 

critical of the fact that the volumes of 

each chemical were not required to be 

reported in addition to the percentages 

of ingredients used. The maximum 

ingredient mass can be calculated from 

the percentages of ingredients reported. 

The BLM did not revise the rule because 

of these comments. 

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One commenter suggested that the 

BLM require operators to report their 

water usage to a public database to 

assure that water usage complies with 

state law and require operators to 

provide evidence of their water rights. 

The BLM does not need to see evidence 

of an operator’s water right. Policing 

water rights is the duty of states and 

tribes, not the BLM. The rule already 

requires operators to report the total 

water volume used for each well. The 

BLM expects that most operators will 

report that information through 

FracFocus. This rule does not preempt 

any state or tribal law requiring 

operators to report water usage to 

another database. 

Hydraulic Fracturing Fluid Constituent 

Data 

One commenter stated that the postfracking reporting requirements should 

clarify that the chemical disclosure is 

just for the chemicals added to the 

hydraulic fracturing fluids and do not 

include naturally occurring chemicals 

in the formation. The BLM concurs with 

this comment and section 3162.3–3(i)(1) 

is revised to clarify that the operator 

must submit a description of each 

additive in the hydraulic fracturing 

fluids. The chemical disclosure will 

include each additive in the hydraulic 

fracturing fluid used by the operator for 

conducting the hydraulic fracturing 

operation. Surface or ground water 

usually includes naturally occurring 

chemicals and may have pollutants from 

other sources. Re-used or recycled water 

will usually not be distilled, but rather 

have traces of chemicals from prior uses 

or by-products from processing. Those 

chemicals are not additives to the 

hydraulic fracturing fluids and will not 

be required to be reported as part of the 

disclosure. If the final rule required 

expensive chemical analysis of reused 

or recycled base fluids, it would 

discourage the use of reused or recycled 

water and put additional demands on 

surface or ground waters needed for 

drinking, agriculture, industry or 

ecosystems, and would increase the 

volume of recovered fluids needing 

permanent disposal. However, even if 

chemicals are naturally occurring in the 

formation, the same chemicals need to 

be disclosed if they are added to base 

fluid for hydraulic fracturing. 

One comment stated that not all 

chemical compounds have CAS 

numbers and therefore could not be 

reported. CAS stands for Chemical 

Abstracts Service, a division of the 

American Chemical Society. The CAS 

number is a unique numerical identifier 

assigned to every chemical substance 

described in the open scientific 

literature. This registry is maintained by 

CAS and is internationally recognized. 

The BLM’s review of disclosure reports 

on FracFocus indicates that the 

chemical substances added to base 

fluids are registered and have a CAS 

number. Therefore, the requirement for 

reporting a CAS number has not been 

changed. Multiple CAS numbers may be 

used if multiple chemical constituents 

are reported for one chemical 

compound. 

Some of the commenters suggested 

that the BLM require both maximum 

and actual concentration of chemicals 

used. The BLM made no change to the 

rule because of this comment. 

Considering the objective of the 

chemical disclosure, the maximum 

concentration provides the worst case 

scenario, which is more important for 

environmental exposure, health, and 

safety of the operation. Percent by mass 

of each chemical is required in the 

hydraulic fracturing fluid to quickly 

evaluate potential exposure. Also, the 

actual concentration of chemicals may 

change as the operator fractures 

different stages of a single well. Thus, 

the maximum concentration provides 

the most useful information toward 

achieving the goal of protecting 

groundwater and developing potential 

response criteria. 

A few commenters asserted that 

listing the maximum concentration of 

the non-MSDS-listed ingredients within 

an additive imparts no real value while 

increasing the risk that the disclosures 

could be used to reverse-engineer 

proprietary formulas for hydraulic 

fracturing additives. The BLM disagrees 

with this comment. The chemicals 

listed on Material Safety Data Sheets 

(MSDS) are believed to be hazardous to 

workers in an occupational setting as 

determined by the Occupational Safety 

and Health Administration (OSHA). 

Other chemicals which do not require 

MSDS, however, might be hazardous to 

humans in an environmental setting 

(such as in ground water used for 

drinking) or might be harmful to the 

environment. Therefore, disclosure of 

these chemicals, including the 

maximum concentration, is necessary. 

Section 3162.3–3(j)(1) of the final rule 

requires affidavits to validate the trade 

secret claims. This requirement will 

allow legitimate exemptions with 

proper documentation and attestations 

in compliance with the previously 

mentioned section. The BLM did not 

revise the rule as a result of this 

comment. Several commenters 

requested disclosure of the volume of 

proppant to be used along with the 

location where the proppant was mined 

or extracted. Final section 3162.3–3(i)(1) 

is revised to require a description of 

each additive in the hydraulic fracturing 

fluid, rather than just each chemical. 

While section 3162.3–3(i)(1) does not 

specifically require the volume of 

proppant to be reported, it does require 

that each additive to the hydraulic 

fracturing fluid be reported along with 

the maximum ingredient concentration 

in the hydraulic fracturing fluid. 

Because a proppant is an additive, it 

must be reported. The volume of 

proppant can be calculated from the 

percentages of ingredients reported. The 

BLM does not believe it to be 

appropriate to require the location 

where the proppant was mined or 

extracted because the BLM would have 

no authority over proppant extraction if 

it were not on public land. If it were on 

public land, it would require a separate 

authorization unrelated to these 

regulations. No changes to the rule were 

made as a result of this comment. 

Some commenters asked that the BLM 

defer to states on matters of disclosure 

of information, including disclosure of 

chemicals used in hydraulic fracturing 

operations. These commenters said that 

states have the best knowledge of the 

geology, and have the experience and 

expertise to make the right decisions. 

The BLM agrees that state agencies are 

well-informed and have much 

experience and expertise, as does the 

BLM. However, chemical reporting 

requirements are not dependent on 

geological conditions. The final rule 

assures that the BLM, states, and the 

public will have access to information 

on the chemicals used in hydraulic 

fracturing operations on Federal and 

Indian land without imposing 

unreasonable burdens on operators. 

Handling and Disposal 

Several commenters suggested 

clarifying the language in sections 

3162.3–3(i)(7)(i) and (7)(ii) (paragraphs 

(5)(ii) and (5)(iii) in the proposed rule) 

to better differentiate handling methods 

from disposal methods. The 

commenters pointed out that hauling by 

truck and transporting by pipeline are 

not disposal methods. The BLM agrees 

and modified the requirement to 

differentiate handling methods (e.g., 

hauling by truck, holding ponds) from 

disposal methods (e.g., injection, off-site 

disposal facility, recycling). 

Several comments objected to the 

requirement that operators report the 

volume of fluid recovered from 

production facility vessels. The BLM 

agrees with this comment and has 

reworded this requirement in final 

section 3162.3–3(i)(6). See the preamble 

discussion under flowback fluids for a 

further explanation. 

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One comment requested that the 

composition of the recovered fluid be 

required as in the original proposed rule 

(77 FR 27710). The BLM did not revise 

the rule as a result of this comment 

because this was not a requirement in 

the supplemental proposed rule and 

because the BLM believes providing 

such information would not be useful. 

This rule aims to treat all recovered 

fluid as potentially hazardous regardless 

of what the chemical constituents may 

be. 

Deviation From Permit 

Numerous commenters stated that the 

rule should be modified to define what 

is meant by a ‘‘deviation from the 

approved plan’’ as required in the 

subsequent report after hydraulic 

fracturing operations have concluded. 

The commenters indicated that it is 

possible for numerous minor deviations 

to occur while conducting hydraulic 

fracturing operations, and that the BLM 

should identify any deviations it 

considers critical. Other commenters 

indicated that the BLM should request 

an explanation and additional 

information regarding issues believed to 

be potentially significant after the 

completion reports have been reviewed. 

The BLM agrees and has modified the 

rule as a result of these comments by 

deleting supplemental section 3162.3– 

3(i)(6). The BLM believes that due to the 

nature of hydraulic fracturing 

operations it is not practical to define, 

or list, all the myriad of outcomes and 

has deleted this specific requirement in 

the final rule. Anomalies or deviations 

are better handled through 

implementation, including both policy 

and training, and BLM engineers will 

identify and resolve deviations when 

reviewing completion reports as the 

BLM handles deviations involving 

approved APDs. This rule and the 

operating regulation provides for the 

authorized officer to request any 

additional information deemed 

necessary for review of the posthydraulic fracturing operation on 

Federal or Indian leases. 

Submission of Logs 

Several commenters expressed 

concern about the requirement under 

the supplemental proposed rule (section 

3162.3–3(i)(8)) requiring operators to 

submit well logs within 30 days of 

completion of hydraulic fracturing. A 

commenter stated this requirement is 

duplicative of the requirements of the 

BLM Well Completion or Recompletion 

Report and Log (Form 3160–4). The 

commenter stated that all logs are 

already provided with the completion 

report. The BLM agrees with this 

comment. As the commenter pointed 

out, operators are required to submit all 

logs with the BLM Well Completion or 

Recompletion Report and Log. Item 21 

of the form requires the operator to 

specify the type of electric and other 

mechanical logs run and indicates 

operators are to submit a copy of each. 

Item 33 of the form requires the operator 

to indicate which items have been 

attached by placing a check in the 

appropriate boxes. The first box is for 

electrical/mechanical logs and in 

parentheses, the operator is reminded 

that ‘‘1 full set req’d.’’ Submission of the 

completion report and the logs is 

required by existing section 3162.4–1(b). 

Since the operators are already required 

to submit all logs, the requirement in 

supplemental section 3162.3–3(i)(8) has 

been deleted in the final rule. 

Additional Information 

Numerous commenters objected to the 

requirement in the supplemental 

proposed rule that the BLM can ask for 

additional information when reviewing 

an application for hydraulic fracturing. 

The commenters stated that this 

requirement is vague, unnecessary, and 

could lead to a broad interpretation by 

local BLM offices. The BLM did not 

revise the rule in response to this 

comment because the BLM must have 

the ability to ask for whatever 

information it needs to adequately 

review an application and fulfill our 

stewardship or trustee obligation. 

Because geology and operations vary 

widely, the BLM needs the flexibility to 

request information relevant to a 

specific or unique proposal and it 

would be unworkable for the BLM to list 

every possible piece of information that 

would cover all hydraulic fracturing 

applications. 

Pressure 

Several comments expressed 

confusion over which pressure the BLM 

required in the subsequent report. 

Supplemental proposed rule section 

3162.3–3(h)(2) asked for the actual 

pump pressure, and section 3162.3– 

3(h)(3) asked for the actual surface 

pressure. The BLM agrees that these 

requirements were confusing and 

revised the final rule to only require the 

maximum surface pressure that was 

applied during the hydraulic fracturing 

operations. The requirements in this 

section were also revised to make them 

consistent with the requirements of the 

NOI in section 3162.3–3(d). 

Section 3162.3–3(j) Information Exempt 

From Public Disclosure 

This section sets out the 

circumstances and procedure under 

which operators may withhold 

information from public disclosure 

under the rule. An operator may 

withhold information as exempt from 

public disclosure only if it identifies a 

Federal statute or regulation that would 

prohibit the BLM from disclosing the 

information if it were in the BLM’s 

possession. The BLM anticipates most if 

not all exemption assertions will be 

made under the Federal Trade Secrets 

Act, 18 U.S.C. 1905, a criminal statute 

which prohibits Federal employees from 

divulging trade secrets and other 

confidential information without 

authorization. The supplemental 

proposed rule would have allowed 

operators to withhold information 

otherwise required to be submitted by 

executing an affidavit affirming that the 

information was a trade secret. The final 

rule modifies the supplemental 

proposed rule at section 3162.3–3(j) in 

several respects. The list of items that 

the operator must affirm has been 

expanded to more completely address 

the factors that are needed to support a 

claim of exemption from public 

disclosure. The operator’s affidavit must 

also identify any other entity, such as a 

contractor or supplier, which would be 

the owner of the withheld information. 

The operator must submit an affidavit 

from such entity that provides any 

information upon which the operator 

relies in executing the operator’s 

affidavit. The operator must affirm that 

it has possession of the withheld 

information so that BLM would have 

access to it upon request. A corporate 

officer, managing partner, or sole 

proprietor must sign the operator’s 

affidavit. Finally, the operator must 

maintain the withheld information for 

the later of the BLM’s approval of the 

final abandonment notice for the well, 

or for Indian lands, 6 years, or for 

Federal lands, 7 years, as provided 

under existing applicable law discussed 

below. As in the supplemental proposed 

rule, the BLM may require the operator 

to provide the withheld information. 

The BLM received numerous 

comments concerning trade secrets and 

confidential business information. Some 

commenters were critical of allowing 

operators to withhold any information 

from the public. Other commenters were 

critical of the role of the BLM in 

deciding whether information would be 

entitled to protection. 

A commenter suggested that the BLM 

defer to states on the handling of trade 

secrets claims, asserting that they were 

state and tribal issues, and should be 

regulated by those authorities. Further, 

the commenter believed that states and 

tribes were better versed in hydraulic 

fracturing operations, and could be 

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stricter than the Federal Government. 

The BLM did not revise the rule in 

response to this comment. No Federal 

statute allows the BLM to defer to 

decisions of states or tribes about what 

information in the BLM’s possession 

will be released to the public, or what 

information the BLM would allow 

operators to withhold from the public. 

Some commenters were critical of the 

supplemental proposed rule for not 

being the same as state rules on trade 

secrets. Many states have adopted the 

Uniform Trade Secrets Act, or have 

other laws governing protection of 

proprietary information. Those state 

statutes do not govern the BLM’s 

compliance with the Federal Trade 

Secrets Act, and the Federal Trade 

Secrets Act does not apply to state 

governments. Thus, the BLM is not in a 

position to concur or to disagree with a 

state’s ‘‘trade secret list,’’ as suggested 

by a commenter. The BLM understands 

concerns about duplication of efforts or 

the potential for inconsistent 

determinations. If a state agency has 

released information to the public 

without restrictions, that information 

would not qualify as a trade secret and 

the BLM would not withhold it from the 

public. Nothing in this rule preempts 

state or tribal laws requiring disclosure 

of information or protecting proprietary 

information. 

Several commenters stated that if the 

BLM continues to allow exemptions 

from public disclosure for information 

on chemical identities in the final rule, 

it should at least require identification 

of the chemical family of the substance. 

The commenters stated this basic 

information does not implicate an 

operator’s trade secrets, but provides at 

least some information about what types 

of chemicals were used by the operator 

in well stimulation. The commenters 

point out that such a rule is feasible 

because a number of states require that 

the chemical family be disclosed where 

a chemical’s identity is withheld as a 

trade secret. Those states include 

Arkansas, Colorado, Louisiana, 

Montana, Oklahoma, Pennsylvania, and 

Texas. The BLM reviewed numerous 

hydraulic fracturing disclosure reports 

in FracFocus. The review revealed that 

many operators are providing the 

chemical family name or other similar 

descriptor for those chemicals that are 

protected as trade secrets. Those include 

reports from states that do not have a 

specific requirement to report on 

FracFocus, and thus were voluntarily 

disclosed. 

A commenter recommended that the 

rule require disclosure of the generic 

chemical name as required under EPA’s 

guidance implementing section 5 of the 

Toxic Substances Control Act (TSCA). 

See Instruction Manual for Reporting 

Under the TSCA § 5 New Chemicals 

Program, p.33 (EPA 2003). The BLM 

believes that the generic chemical name 

that was or should be provided to the 

EPA under TSCA or other statutes and 

published in the Federal Register would 

not constitute a trade secret because it 

is or should be public, and the operator 

can still withhold the specific chemical 

identity. The BLM also concludes that 

requiring the generic chemical name 

would promote consistency with the 

EPA’s implementation of TSCA and 

other statutes for confidential chemical 

information, and thus would be less 

confusing for owners of information and 

the public. Therefore, final section 

3162.3–3(j)(6) requires the operator to 

include the generic chemical name for 

each such chemical. The BLM expects 

that the generic chemical name 

submitted pursuant to this rule will be 

the same as that submitted to EPA; if the 

generic chemical name is less 

descriptive than that submitted to EPA, 

the owner of the information should 

have a credible explanation for the 

difference. 

The supplemental proposed rule at 

section 3162.3–3(j)(4) would have 

required operators to retain in their 

records the information they claimed to 

be exempt from disclosure for 6 years, 

by reference to the existing regulations 

at 43 CFR 3162.4–1(d). The rule 

expressly requested comments on 

whether another retention time would 

be more appropriate. The BLM received 

many comments on that topic. A few 

commenters favored the 6-year retention 

period, though more favored shorter 

periods. Many other commenters 

favored longer retention periods; several 

favored that records be retained for the 

life of the well, and a few advocated 

perpetual retention. 

Final rule section 3162.3(j)(5) requires 

operators to retain information that is 

withheld from the BLM until the later 

of the approval of the notice of final 

abandonment of the well (i.e., the ‘‘life 

of the well’’), or 6 years after the 

completion of hydraulic fracturing 

operations on Indian lands, or 7 years 

after completion of hydraulic fracturing 

operations on Federal lands. The BLM’s 

need to have access to information 

about chemicals injected into Federal or 

Indian minerals may arise at any time. 

However, a perpetual retention 

requirement would not be appropriate 

because an operator’s responsibility for 

a well ends (for purposes of most of the 

BLM’s regulations) when the BLM 

approves the operator’s notice of final 

abandonment of the well. 

A 6-year minimum retention period 

on Indian lands is not burdensome 

because operators are already required 

under the Federal Oil and Gas Royalty 

Management Act (FOGRMA) and 

regulations to retain all records for a 

minimum of 6 years, including records 

and reports they submit to the BLM. See 

30 U.S.C. 1713(b); 43 CFR 3162.4–1(d). 

A 7-year minimum retention period is 

not burdensome because operators on 

Federal lands are already required 

under the Federal Oil and Gas Royalty 

Simplification and Fairness Act of 1996 

(FOGRSFA), 30 U.S.C. 1724(f), to retain 

all records for determining compliance 

with any regulation with respect to 

Federal oil and gas leases for 7 years. 

BLM’s regulations at 43 CFR 3162.4– 

1(d) have not been updated to reflect 

that statutory obligation, but there is no 

impediment to this final rule requiring 

retention of data for a minimum of 7 

years. Although FOGRSFA precludes 

the BLM from requiring longer retention 

of records pertaining to financial 

obligations (such as royalties), it does 

not preclude longer retention of records 

pertaining to other requirements for 

onshore oil and gas operations. 

FOGRSFA does not apply to Indian 

lands, and therefore the 6-year retention 

period in 30 U.S.C. 1713(b) applies to 

those lands. 

Requiring trade secret records to be 

retained for the life of the well, if that 

life is longer than 6 or 7 years, is fair 

and reasonable because if an operator 

withholds the information under the 

rule (section 3162.3–3(j)(1)) the 

operator’s records of the withheld 

information may be the only records of 

the chemicals injected into Federal or 

Indian minerals. Therefore, the BLM 

believes that it is necessary to have 

access to that information for the life of 

the well, and that the 6-year and 7-year 

retention periods in the pertinent 

statutes are minimum requirements 

with respect to records that do not 

pertain to financial obligations. 

Some commenters said that the rule 

would fail to protect trade secrets, or 

that it mandated disclosure, putting the 

BLM and its employees at risk of 

lawsuits. The BLM disagrees. This rule, 

like the supplemental proposed rule, 

allows operators initially to withhold 

specific information by submitting an 

affidavit from the operator 

demonstrating that the information is 

protected from disclosure by law. The 

BLM retains authority to require 

operators to submit any of the initially 

withheld information. If the BLM 

decides that the information is not a 

trade secret, it would provide advance 

notice so that the operator or owner of 

the information could seek a court order 

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restraining disclosure to the public. The 

rule provides the same procedural 

safeguards for hydraulic fracturing 

information as for all other information 

obtained by the Department. 

Some commenters expressed 

confusion about who would determine 

whether identities of chemicals were 

entitled to be withheld from the public 

as trade secrets. Under this final rule, in 

the first instance, the operator would 

either disclose the information or would 

withhold specific information and 

submit an affidavit. If the BLM 

requested the withheld information, the 

operator would be required to provide 

it. The BLM would determine if the 

information is a trade secret. As 

described earlier, if the BLM determines 

that the information is not a trade secret, 

the operator and owner of the 

information would have an opportunity 

to challenge the BLM’s determination in 

Federal district court. 

Some commenters were critical of the 

revised proposed rule for not defining 

trade secrets. The Federal Trade Secrets 

Act does not define trade secrets, and 

does not expressly authorize Federal 

agencies to define trade secrets. The 

BLM will make any decisions regarding 

trade secrets and other confidential 

information based on relevant Federal 

judicial opinions. See, e.g., Canadian 

Commer. Corp. v. Air Force, 514 F.3d 

37, 39 (D.C. Cir. 2008) (‘‘We have long 

held the Trade Secrets Act . . . is ‘at 

least co-extensive with . . . Exemption 

4 of FOIA.’ ’’) (citation omitted); 

National Parks & Conserv’n Ass’n v. 

Morton, 498 F. 2d 765 (D.C. Cir. 1974) 

(discussing meaning of privileged or 

confidential commercial or financial 

information); Public Citizen Health 

Research Group v. FDA, 704 F.2d 1280, 

1288–89 (D.C. Cir. 1983) (‘‘trade secret’’ 

in exemption 4 means a ‘‘commercially 

valuable plan, formula, process, or 

device that is used for the making, 

preparing, compounding, or processing 

of trade commodities and that can be 

said to be the end product of either 

innovation or substantial efforts’’). 

Other commenters asserted that 10 

business days’ notice before releasing 

information was insufficient, and one 

said that it would stifle development of 

more environmentally benign 

chemicals. The BLM disagrees. Similar 

to the Department’s FOIA regulations, 

the final rule requires a minimum of 10 

business days’ notice prior to releasing 

information determined not to be 

exempt from disclosure. Cf. 43 CFR 

2.33(c). That time is sufficient for the 

submitter to seek a temporary 

restraining order from a court. Also, the 

BLM would give due consideration to 

all relevant factors, including whether 

the information is the end product of 

innovation, in deciding whether the 

information is a trade secret. 

Many commenters objected to the 

requirement that the operator certify 

that withheld chemical information is a 

trade secret. They said that the trade 

secrets are owned by the service 

contractors, and that the operator has no 

knowledge of them or ability to certify. 

Some said that the BLM should place 

the burden on the service contractors 

and not the operator. One commenter 

said that chemical manufacturers invest 

great sums in developing their products, 

and should not have to rely on oil and 

gas operators (or apparently, service 

providers) to assert and defend their 

trade secrets. The BLM disagrees in part. 

The BLM is aware that the common 

practice is for operators to engage 

service companies to conduct hydraulic 

fracturing services. The existing 

regulations are clear, however, that an 

operator cannot use a contract with a 

third party to escape responsibility for 

all operations on the permitted well site. 

See existing section 3162.3(b). Whether 

or not chemical suppliers or service 

contractors would ‘‘own’’ the 

information about the chemicals, it is 

the operator who has voluntarily taken 

responsibility for all operations in and 

on its wells, including hydraulic 

fracturing, and it is the operator who is 

responsible for submitting all required 

reports and information. Nonetheless, 

because the operator will not always be 

in the best position to declare why 

certain information should be withheld, 

the final rule allows the operator to 

submit an affidavit from the owner of 

the information attesting to the 

confidential status of the information in 

addition to the affidavit required from 

the operator. When the BLM is deciding 

whether alleged trade secret information 

it has received may be disclosed to the 

public, both the operator and the owner 

of the information may provide the BLM 

with any materials that would 

substantiate a claim of trade secret 

status, and both the operator and the 

owner of the information would receive 

advance notice of any BLM decision 

that the information is not a trade secret. 

Some commenters asked that trade 

secret protection be extended to other 

required information, such as elements 

in the NOI. As with any submission of 

information to a Federal agency, the 

submitter may segregate the information 

it believes is a trade secret, and explain 

and justify its request that the 

information be withheld from the 

public. 

Many commenters addressed other 

issues concerning trade secrets. Some 

commenters opposed allowing operators 

to withhold trade secrets from public 

disclosure. Other commenters asserted 

that the BLM was arbitrarily ignoring 

the recommendations of the Secretary of 

Energy’s advisory task force that all 

chemicals should be disclosed to the 

public without exception. The BLM has 

no authority to require public disclosure 

of information that is entitled to 

protection under the Federal Trade 

Secrets Act. There is nothing arbitrary 

in assuring the compliance of BLM 

employees with a Federal criminal 

statute. 

Some commenters said that the BLM’s 

authority to promulgate regulations 

provides the BLM authority to require 

public disclosure by regulation, 

obviating protection under the Trade 

Secrets Act, citing, e.g., Chrysler Corp. 

v. Brown, 441 U.S. 281 (1979) [Chrysler]. 

The Supreme Court in Chrysler 

established a three-part test for 

determining whether an agency rule 

may exempt information from the Trade 

Secrets Act: (1) The rule must be 

substantive; (2) It must be issued in 

accordance with statutory procedures; 

and (3) The rule must be based on a 

statutory grant of authority allowing the 

agency to disclose privileged 

information. This rule satisfies parts 1 

and 2 of the Chrysler test. But the BLM’s 

authorizing statutes do not expressly 

authorize regulations requiring 

disclosure of privileged information. 

Thus, the final rule is not revised in 

response to those comments. 

Some commenters urged the BLM to 

require operators to submit trade secret 

information to the BLM, even if the 

BLM was required to maintain 

confidentiality, in order to encourage 

operators to make only good faith claims 

of trade secret protection. Some 

commenters said that the BLM should 

require operators to justify their trade 

secret claims. Some commenters said 

that the BLM should individually 

validate each claim of trade secret 

status. The BLM believes that the 

affidavit requirements are sufficient to 

assure that the vast majority of operators 

will assert only good faith claims for 

trade secret protection. But although the 

BLM will not be individually 

adjudicating each claim of trade secret 

status, the BLM agrees with those 

commenters in part. The BLM has 

revised the affidavit requirements to 

address all of the factors that the BLM 

would need to consider in deciding 

whether to release the information. The 

final rule requires the operator to affirm 

that it or any other owner of the 

information is in actual competition, 

identify competitors that would be 

interested in the withheld information, 

and affirm that release of the 

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information would likely cause 

substantial competitive harm and 

provide the reasons for that affirmation. 

If the operator is relying on information 

from its contractors or suppliers, the 

operator will need to provide affidavits 

from those entities supporting that 

reliance. Although additional 

supporting facts might be required if the 

BLM had to decide whether the 

information is a trade secret, the BLM 

could request those additional facts. 

Furthermore, the final rule requires that 

the affidavit be signed by a corporate 

officer, managing partner, or sole 

proprietor of the operator. That will 

discourage bad-faith assertions of trade 

secret protection. 

A commenter suggested that, in 

addition to the affidavit, an operator 

should be required to provide 

independent verification that the 

information is a trade secret. The BLM 

will not require an operator to disclose 

proprietary information to an industry 

trade group as suggested by the 

commenter, in order to assert trade 

secret protection. Even if it were within 

the BLM’s discretion, it would place 

industry trade groups in a role they have 

not requested. 

Some commenters suggested that the 

BLM establish a procedure for citizens 

to challenge affidavits for withholding 

trade secret information. The BLM’s 

resources will be better devoted to 

implementing this rule to assure 

protection of usable water from 

hydraulic fracturing fluids than in 

adjudicating uncontrollable numbers of 

challenges to affidavits. If the BLM has 

reason to believe that an affidavit is 

incomplete or inaccurate, or that it 

needs the information for any purpose, 

including a random inspection, it can 

demand the withheld information and 

make a determination if it is truly a 

trade secret. Additionally, the BLM 

encourages voluntary disclosure of 

fracturing fluids to the public, as some 

companies in the oil and gas industry 

have begun to do. Some commenters 

urged the BLM to require operators to 

disclose trade secret information in the 

event of a medical emergency. Other 

commenters stated that the material 

safety data sheets (MSDS) required by 

the OSHA are adequate for disclosure to 

medical personnel and first responders. 

The BLM understands the need for first 

responders and medical personnel to 

have complete information about 

potential chemical exposures in the 

event of an accident. However, unlike 

many state laws, the Federal Trade 

Secrets Act does not include an 

exception for medical or other 

emergencies. If the BLM requests the 

withheld information, and any Federal 

law required the BLM to provide it to 

another entity, the BLM would comply 

with that law. Note though, however, 

that nothing in this rule exempts 

operators or their contractors from 

complying with all applicable 

regulations of the OSHA, including 

requirements concerning MSDS. 

Furthermore, nothing in this rule 

preempts laws of states and localities 

(on Federal lands) or of tribes (on tribal 

land) requiring disclosure of 

information to first responders or to 

medical personnel. 

Some commenters doubted the BLM’s 

ability to make informed management 

decisions without complete information 

about the chemicals being used. The 

BLM disagrees. The BLM understands 

that hydraulic fracturing operations will 

use chemicals that are potentially 

hazardous. Compliance with this rule 

will assure that those chemicals are 

isolated from sources of usable water. 

A commenter suggested deleting the 

‘‘maximum ingredient concentration in 

additive (percent by mass)’’ 

requirement, arguing that it would have 

the effect of creating more trade secret 

exemptions, and that from an 

environmental perspective, what 

matters is the total concentration of a 

chemical. The BLM believes that the 

comment has merit, but there are costs 

and benefits to either approach. On 

balance, the rule is not revised in 

response. On the one hand, it is possible 

that if the rule does not require the 

percent by mass maximum ingredient 

concentration, more of the chemicals 

used in hydraulic fracturing operations 

would be disclosed because the risk of 

reverse-engineering would be reduced. 

On the other hand, the GWPC requests 

the percent by mass on its FracFocus 

data sheet and the industry has shown 

a willingness to furnish that 

information. As a result, the final rule 

requires disclosure of the percent by 

mass. The BLM notes that operators may 

seek to withhold the percent by mass as 

a trade secret, and to disclose the 

identity of the particular chemicals. 

That could be appropriate where the 

particular chemicals are not unusual, 

but the operator believes it has a 

valuable formula that optimizes the 

concentrations. 

A commenter recommended that 

trade secret protection be denied unless 

there were a patent or a patent 

application pending for the chemicals. 

The Federal Trade Secrets Act does not 

have such a restriction and the BLM has 

no authority to impose one in this 

regulation. The final rule is not revised 

in response to that comment. 

Some commenters recommended that 

operators should be able to obtain trade 

secret protection prior to conducting 

hydraulic fracturing operations, either 

in an NOI, or in a ‘‘master chemical 

plan.’’ The BLM disagrees. The BLM is 

not requiring submission of the 

identities of chemicals proposed to be 

used in hydraulic fracturing operations. 

Only the chemicals actually used in 

those operations would need to be 

either disclosed, or withheld by 

submitting an affidavit. The final rule is 

not revised in response to those 

comments. 

Some commenters expressed 

uncertainty about what statute would 

prohibit disclosure of the identities of 

chemicals for purposes of final section 

3162.3–3(j)(1)(ii). The BLM believes that 

most claims would be made under the 

Federal Trade Secrets Act, but the final 

rule leaves the category open in case 

any other statute might apply to certain 

information. The final rule is not 

revised in response to these comments. 

A commenter recommended changing 

the affirmation required in the affidavit 

to ‘‘the best of the operator’s knowledge 

at the time.’’ The final rule is not 

revised in response to that comment. 

Withholding the identities of chemicals 

injected into Federal or Indian minerals 

is a privilege, and to earn that privilege 

the operator must make informed 

declarations in the affidavit. If the 

operator is relying on information from 

a contractor or supplier, the rule 

requires that the operator provide an 

affidavit from that entity setting forth 

that information. 

A commenter recommended deleting 

the affirmation as unnecessary. The 

BLM disagrees. The BLM believes that 

the affirmation is appropriate and has 

not revised the rule in response to that 

comment. 

Some commenters urged that the 

records of the chemical identities 

withheld as trade secrets should be 

retained by the service contractors, not 

by the operators. As previously 

explained, operators are responsible for 

their contractors’ actions on the well 

sites. Maintaining accurate and 

complete well records with respect to 

all lease operations is the operator’s 

responsibility. See existing section 

3162.4–1(a). Indeed, the admissions in 

comments that some operators are not 

currently retaining all information about 

hydraulic fracturing operations raise 

concerns. Note though, that nothing in 

the rule prevents an operator from 

maintaining the confidential 

information under a physical or an 

electronic seal that would notify the 

owner of the information when it was 

accessed, as long as the BLM will have 

access to it upon request. 

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Furthermore, in response to 

comments stating that owners of trade 

secret chemical information would not 

allow operators to possess it, the final 

rule provides that an operator will be 

deemed to be maintaining the required 

information if it can promptly provide 

it to the BLM upon request, even if the 

information is in the custody of its 

owner. Any successor operator will be 

responsible for maintaining that access 

for the retention period in this rule. 

Section 3162.3–3(k) Variances 

This section allows operators to 

request a variance from the 

requirements of this final rule. Variance 

language is common among BLM 

regulations. Under this provision, the 

BLM will consider alternatives if an 

operator can demonstrate that the 

objectives of the rule would be met 

using an alternate approach. 

Three changes are made to this 

section. First, this section is reorganized 

for clarity, segregating requirements for 

individual variances and state or tribal 

variances. Second, this section has been 

revised to clarify that the authority to 

approve a variance that applies to all 

wells within a state or within Indian 

lands, lies with the State Director. 

Third, this section has been revised to 

make paragraph (k)(3) consistent with 

existing regulations in Onshore Order 1 

by adding language stating that the 

decision on a variance request is not 

subject to administrative appeal either 

to the State Director or under 43 CFR 

part 4. 

Numerous commenters said that the 

rule should be revised to prohibit 

blanket variances for operators. The 

BLM did not revise the rule as a result 

of these comments. No blanket variance 

provisions for hydraulic fracturing 

operations exist in the rule. As 

provided, variances may be granted on 

a case-by-case basis from a specific 

provision of the rule, within a state, or 

on a tribal basis. Individual variances 

could only be granted where the 

operator’s proposal meets or exceeds the 

objectives of the rule, and state or tribal 

variances may only be granted if the 

state or tribal provisions meet or exceed 

the objectives of the rule. A variance 

granted pursuant to this rule would not 

be an exemption from the goals of this 

rule, and would not be an abdication of 

the Secretary’s stewardship 

responsibilities on Federal lands or trust 

responsibilities on Indian lands. 

Numerous commenters stated that the 

rule should be revised to disallow 

variances of any kind or that variances 

should be limited. The BLM did not 

make any changes as a result of these 

comments. The BLM believes that it is 

practical to include a variance provision 

since the rule cannot contemplate all 

possible hydraulic fracturing 

circumstances which may be 

encountered on a national basis and 

must include provisions to address 

those unique or local circumstances, or 

improved technologies. The BLM 

believes, however, that variances should 

only be granted when it is clear that the 

alternative requirement is equally or 

more protective than the BLM’s rule. 

Several commenters indicated that the 

variance definition is vague and could 

allow for waiving of hydraulic 

fracturing requirements. Other 

commenters requested further 

clarification or suggested alternative 

language for this section. The BLM did 

not revise the rule as a result of these 

comments. While the rule does not 

contain a specific variance definition, 

the variance provisions in the rule are 

substantially similar to existing 

provisions in 43 CFR 3162.7–5(b)(9) as 

well as in Onshore Orders 2 through 7 

regarding variances. All hydraulic 

fracturing operations on Federal or 

Indian leases must still meet or exceed 

the objectives of the requirement for 

which a variance is being requested. 

Several commenters said that the rule 

should be revised to include the 

procedure and criteria for requesting a 

variance. The commenters indicated 

that the rule should provide 

clarification on the variance-issuance 

process and expressed concern that the 

supplemental proposed rulemaking 

contained no mechanism to notify the 

public. The BLM did not revise the rule 

as a result of these comments. 

Throughout this rulemaking the BLM 

has been aware that members of the 

public are concerned about hydraulic 

fracturing. While specific processing 

details regarding hydraulic fracturing 

variances have yet to be developed, the 

notification process may be made 

available to the public for statewide and 

tribal variances. The BLM will post all 

variances on its Web site. 

Several commenters said that the rule 

should be revised to address how 

variances will be implemented. Other 

commenters indicated that all variances 

should be written; that no oral variances 

should be allowed. The BLM did not 

revise the rule as a result of these 

comments. The final rule specifies the 

procedural steps for several different 

variance processes. 

Additionally, final section 3162.3– 

3(k)(1) contains no provision for oral 

variances. The BLM envisions that the 

majority of case-by-case variances will 

be authorized in the same manner as 

existing variances are authorized and 

that is via Sundry Notices. Each 

variance request must contain specific 

information justifying why a variance is 

needed. For state or tribal variances, the 

provisions will depend on the formal 

agreement between the involved agency 

and the BLM. It is not possible to 

envision or regulate all the possibilities 

and therefore these rules provide 

flexibility and discretion to the local 

BLM manager. 

Several commenters expressed 

concern regarding section 3162.3– 

3(k)(5) in the final rule (paragraph 

3162.3–3(k)(4) in the supplemental 

proposed rule) which allows the BLM 

the right to rescind a variance. The 

commenters stated that this is 

extraordinarily broad language that does 

not provide any factual criteria that the 

BLM must meet before modifying or 

revoking a variance. In their view, the 

proposed variance process fails to 

provide operators with a reasonable 

assurance that regulatory requirements 

will not arbitrarily change. Commenters 

also stated that if the variance language 

remains in the rule, the BLM should be 

required to provide operators notice of 

its intent to rescind or modify a variance 

in writing, provide operators at least 30 

days to respond, and provide that any 

final decision on variances not become 

effective until at least 30 days after 

receipt by the operator. The BLM agrees 

in part. The authorized officer will grant 

a variance only if the BLM determines 

that the proposed alternative meets or 

exceeds the objectives of the regulation 

for which the variance is being 

requested. The BLM understands that 

operators are likely to rely on a variance 

in planning and executing their 

operations. A decision to rescind a 

variance would only occur after a 

thorough internal process has been 

undertaken. But if the BLM later 

determines that a particular variance 

fails to meet the objectives of the 

regulation, the BLM must retain the 

right to rescind that variance. In 

addition, changes in Federal laws or 

changes in technology may dictate the 

need to rescind a variance. While the 

BLM appreciates the issues raised by the 

commenters, these concerns do not 

override the BLM’s responsibility to 

manage the public lands to prevent 

unnecessary or undue degradation, and 

to assure proper resource protection on 

Federal and Indian lands. While no 

timeframe is described, the rule requires 

that the authorized officer provide a 

written justification if a variance is 

rescinded. The rule does not require 

prior notification, but it also does not 

prohibit the local BLM manager from 

providing prior notification of a 

rescission of a variance when 

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appropriate. No revisions to the rule 

were made as a result of these 

comments. 

State and Tribal Variances 

Numerous commenters said that the 

rule should be revised to establish the 

process for state-initiated variances. 

Commenters indicated that the rules 

lacked specificity in this regard and 

provided specific language for a ‘‘state 

equivalency determination’’ process 

which enumerated the steps a state 

agency would utilize as well as the 

process that binds the BLM in reviewing 

and approving such proposals. The BLM 

did not revise the rule as a result of 

these comments. State or tribal 

variances would be approved as a result 

of discussions among the BLM and the 

state or tribal agencies, which do not 

require a rigid process specified in 

regulations. A state or tribal variance is 

not a delegation of full or partial 

regulatory primacy, so a ‘‘state 

equivalency determination’’ process is 

neither necessary nor appropriate. 

One commenter supported section 

3162.3–3(k), which allows for the BLM 

to work in cooperation with a tribe and 

issue a variance that would apply to all 

wells within Indian lands or to specific 

fields or basins within Indian lands. The 

commenter, however, recommended 

that the rule be expanded to include the 

process that tribes would use to initiate 

a variance. The BLM does not believe 

the rule needs to be expanded to 

include the specific mechanism for 

approving variances with tribes since it 

may vary from tribe to tribe. The BLM 

will work cooperatively with any tribe 

or state to craft variances that would 

allow technologies, processes, or 

standards required or allowed by the 

state or tribe to be accepted as 

compliance with the rule. Such 

variances would allow the BLM and the 

states and tribes to improve efficiency 

and reduce costs for operators and for 

the agencies. 

Numerous commenters stated that the 

rule should be revised to provide for 

statewide exemptions from the 

hydraulic fracturing rule. Other 

commenters suggested modifying the 

variance section so that the BLM’s 

hydraulic fracturing rule should only 

apply in those states which do not have 

hydraulic fracturing rules. The BLM did 

not revise the rule as a result of these 

comments. The Secretary of the Interior 

has stewardship responsibilities on 

public lands and trust responsibilities 

on Indian land. Accordingly, the BLM is 

promulgating a rule that governs 

hydraulic fracturing operations on all 

Federal and Indian leases. While the 

BLM does not provide for statewide 

exemptions from the entire hydraulic 

fracturing rule, variances may be 

granted for individual provisions of the 

rule, if the variance proposal meets or 

exceeds the objectives of the rule. The 

BLM encourages formal agreements 

with state or tribal agencies to avoid 

overlap and promote cooperation 

amongst regulatory bodies and to reduce 

compliance burdens on operators. 

Numerous commenters said that the 

rule should be revised to recognize 

existing state agency rules. The 

commenters indicated that under such a 

provision the need for any variance 

would then be redundant because all 

proposals would clear the ‘‘meets or 

exceeds’’ state threshold. The BLM did 

not revise the rule as a result of these 

comments. While numerous states have 

hydraulic fracturing rules in place or are 

currently contemplating hydraulic 

fracturing rules, the applicability and 

content of these rules are not consistent 

across all BLM-managed public lands in 

those states. Additionally, certain states 

do not have hydraulic fracturing rules at 

all. In addition, state rules may not 

apply to tribal lands. The BLM will 

work closely and cooperatively with 

state and tribal agencies to implement 

these rules to avoid overlap and 

duplication where possible. Formal 

agreements with state and tribal 

agencies are encouraged. 

Numerous commenters said that the 

rule should be modified to allow for 

statewide or tribal variances. 

Commenters indicated that states 

should regulate hydraulic fracturing 

operations on all lands within that state 

by memorandum of understanding. The 

BLM agrees with those comments in 

part, and has modified the rule as a 

result of these comments. The rule has 

been edited to clarify that there are two 

types of variances: Individual (or 

operator-specific), and state or tribal (for 

wells on all or designated portions of 

state or tribal lands). As provided, 

variances may be granted to states and 

tribes, only if the state or tribal 

requirements meet or exceed the 

objectives of the rule. The rule also 

provides that state or tribal variances 

maybe initiated by the involved state, 

tribe, or the BLM. 

The BLM may approve a variance 

under paragraph 3162.3–3(k) from one 

or more specific requirements of the 

rule, but not from the entire rule. The 

variance provision does not allow the 

BLM to delegate regulation of hydraulic 

fracturing operations on public or 

Indian lands to state agencies. Unlike 

several other environmental statutes, 

none of the BLM’s statutory authorities 

authorize delegation of the BLM’s 

regulatory duties to state or tribal 

agencies. 

Section 3162.5–2(d) Isolation of 

Usable Water 

The changes to this section conforms 

the out-of-date language in this section 

with the Onshore Order 2 requirements. 

Onshore Order 2 superseded the 

existing regulations in 1988, because it 

was promulgated pursuant to noticeand-comment rulemaking. Since the 

final rule is consistent with Onshore 

Order 2, it does not represent a change 

in policy. 

The BLM received numerous 

comments on the subject of usable 

water. Those comments are addressed 

under the section 3160.0–5 discussion 

in this preamble. This section is not 

revised in the final rule and remains as 

proposed. 

General Comments 

Incorporate API Standards 

Several commenters recommended 

that the BLM adopt American Petroleum 

Institute (API) Guidance Document HF1, 

First Edition (October 2009) (HF1) 

instead of developing its own standards. 

During the development of the rule, the 

BLM not only considered all comments 

received but also consulted numerous 

other sources including API HF–1, state 

regulations, and academic and 

professional papers such as King, 

George, SPE 152596, ‘‘Hydraulic 

Fracturing 101: What Every 

Representative, Environmentalist, 

Regulator, Reporter, Investor, University 

Researcher, Neighbor, and Engineer 

Should Know About Estimating Frac 

Risk and Improving Frac Performance in 

Unconventional Gas and Oil Wells,’’ 

Society of Petroleum Engineers, 

Hydraulic Fracturing Technology 

Conference, (Feb. 2012). The BLM does 

not believe that the rule should 

incorporate any particular guidance. 

Although the BLM has carefully 

considered the API HF1 and HF2 

guidance as we developed this rule, the 

BLM cannot fully incorporate the 

guidance documents because they do 

not meet all of the BLM’s areas of 

concern for protection of resources on 

Federal and Indian lands. Moreover, 

nothing in this final rule precludes an 

operator from following recommended 

industry guidance. See the following 

table for a comparison of applicable 

components of API HF1 guidance and 

the final rule. 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16177 

Subject API HF–1 Final rule/Onshore Order 2 

Surface casing ..................... Set at least 100′ below lowest USDW (deep water 

zones can be isolated by intermediate or production 

casing).

Usable water must be isolated by casing (not necessarily by surface casing). 

Cement to surface ........................................................... Cement to surface (Onshore Order 2). 

If no cement to surface, must identify top of cement 

with CEL or temperature log. 

If fallback >200 feet or 10 percent of surface casing 

depth, must identify top of cement with CEL or temperature log. 

Monitor and record flow rate, density, and pump pressure. 

Intermediate casing .............. Cement above any USDW or hydrocarbon bearing 

zone.

CBL recommended ......................................................... CEL required if casing is used to isolate usable water 

and not cemented to surface 

Monitor and record flow rate, density, and pump pressure if casing used to isolate usable water. 

Production casing ................ Tail cement (the last cement system pumped during 

primary cementing which covers the lower sections of 

the well) should be brought 500′ above producing 

formation.

200 feet of adequately bonded cement between the 

fractured zone and the deepest usable water zone, 

could be either production or intermediate casing. 

Tail cement should extend above the top of confining 

formation.

Should consider CBL for cement evaluation .................. CEL required if casing is used to isolate usable water 

and not cemented to surface 

Monitor and record flow rate, density, and pump pressure if casing used to isolate usable water. 

All casing .............................. Pressure test ................................................................... Pressure test (Onshore Order 2). 

Formation integrity test after drilling out ......................... Formation integrity test if exploratory well or if the blowout prevention equipment is 5,000 psi or greater (Onshore Order 2). 

Take remedial action if pressure tests fail ...................... Take remedial action if there are indications of inadequate cement. 

Pressure test prior to hydraulic fracturing.Test all hydraulic fracturing surface equipment .............. Mechanical Integrity Test: Pressure test casing or fracturing string to maximum anticipated pressure. 

Baseline water monitoring ... Test water samples from nearby water sources prior to 

drilling.

Monitoring during hydraulic 

fracturing.

During hydraulic fracturing, monitor injection pressure, 

slurry rate, proppant concentration, fluid rate, and 

proppant rate.

Monitor and report actual pump pressure, fluid rate, 

and flush volume. 

Monitor annular pressure (all annuli) .............................. Monitor annular pressure (all annuli). 

Monitor unexplained deviations from plan ...................... Annular pressure increase greater than 500 psi requires corrective action. 

Pressure should not exceed working pressure of weakest component.

Relief valve on intermediate casing annulus—set not to 

exceed working pressure of casing; flowline diverted 

to lined pit or tank.

Monitoring after HF .............. Monitor annular pressure after hydraulic fracturing; assign max/min.

Enforcement and Implementation of 

Rules 

Several commenters stated that there 

is concern that the BLM is imposing 

new rules when the BLM does not have 

the staffing, budget, or the number of 

experts needed to implement the rule or 

requisite expertise to evaluate fracturing 

proposals, which would cause delays in 

approvals and decreased Federal and 

Indian oil and gas production. The BLM 

does not agree with the assertion 

regarding the lack of BLM staff 

expertise. The BLM employs qualified 

and experienced petroleum engineers 

and geologists. The BLM understands 

the time-sensitive nature of oil and gas 

drilling and well completion activities 

and does not anticipate that the review 

of additional information related to 

hydraulic fracturing with an APD will 

impact the timing of the approval of 

drilling permits. The BLM believes that 

the additional information that would 

be required by this rule would be 

reviewed in conjunction with the APD 

and within the normal APD processing 

timeframe. If an operator submits a 

request in an NOI, however, further 

processing time should be expected. 

The BLM understands that delays in 

approvals of operations can be costly to 

operators and the BLM intends to avoid 

delays whenever possible. Also, the 

revisions made from the supplemental 

rule to final rule would reduce the 

amount of staff time required to 

implement the rule and limit any 

permitting delays. The changes include 

eliminating the type well concept and 

the requirement for a CEL to be run and 

submitted for a type well prior to 

completing additional wells. 

Several commenters said that the rule 

should be modified to provide 

enforcement provisions. The 

commenters stated that the BLM must 

monitor hydraulic fracturing operations 

on Federal and tribal lands to ensure 

compliance with the rules. The BLM did 

not make any changes as a result of 

these comments. Monitoring performed 

by the BLM is a matter of 

implementation and policy, not 

regulation, and therefore, revision of the 

rule for monitoring is not warranted. 

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Additionally, enforcement is outside the 

scope of this rulemaking. The rule does 

not address compliance and 

enforcement issues because those issues 

are already covered by existing 

regulations in subpart 3163. More 

specifically, existing section 3163.1 

addresses the remedies for acts of 

noncompliance. The remedies include 

written notices of the violation, 

assessments, and shut down of 

operations. Continued noncompliance 

could lead to civil penalties and 

possible lease cancellation. See existing 

section 3163.2. The law also provides 

for criminal liability for certain false 

statements in public land matters, 

whether sworn or unsworn. 18 U.S.C. 

1001; 43 U.S.C. 1212. 

Commenters also expressed concern 

that depending on self-reporting by the 

operators would be unreliable. The 

BLM, in line with its authority, has 

historically relied on self-reporting 

throughout the oil and gas program (e.g., 

production volumes and completion 

information). In order to verify the selfreporting, the BLM conducts regular 

inspections of operations. The BLM 

conducts inspections in accordance 

with an annual risk-based strategy to 

ensure compliance with the regulations. 

The BLM has a funding request in place 

that will lead to improved Inspection 

and Enforcement resources and 

performance. The BLM’s oil and gas 

program has no greater priority than 

ensuring that development is done 

safely and responsibly. No revisions to 

the rule were made as a result of these 

comments. 

One commenter expressed concern 

over how the BLM will know if an 

operator fails to report a wellbore issue. 

The BLM has a number of mechanisms 

that would indicate if an operator failed 

to report a wellbore issue. The BLM 

routinely conducts inspections of 

ongoing operations. These inspections 

consist of witnessing operations, such as 

the cementing of casing, onsite review 

of the drillers log at the rig, or the 

review of documentation such as the 

third-party cementing ticket. Through 

witnessing the operation or the review 

of the documentation, the BLM 

inspectors can verify that operations 

were conducted in accordance with the 

approved plan and that no wellbore 

issues exist. Operators also must submit 

a subsequent report as required by final 

section 3162.3–3(i). BLM staff will 

review the information included in the 

subsequent report to identify any 

deviations from the approved plan, or 

any indications of wellbore issues. In 

addition, under final section 3162.3– 

3(i), the operator must certify that it 

complied with the paragraphs of the 

rule that assure wellbore integrity was 

maintained prior to and throughout the 

hydraulic fracturing operation. No 

revisions to the rule were made as a 

result of this comment. 

One commenter recommended that 

each operator designate one or more 

individuals to be prosecuted criminally 

if criminal negligence, fraud, or 

conspiracy were found in any hydraulic 

fracturing operation. The commenter 

also recommended that an independent 

counsel be appointed to investigate 

death or disability caused by hydraulic 

fracturing operations, and a freezing of 

corporate stock pending such 

investigation. While criminal liability 

and criminal investigations are beyond 

the scope of this rulemaking, any 

information of potential criminal 

violations would be appropriately 

addressed by law enforcement 

authorities. 

Some commenters wanted the BLM to 

add an appeal process for decisions to 

condition or to deny a hydraulic 

fracturing proposal, and wanted rules 

for the standing of third parties. The 

Department’s regulations already 

provide procedures for administrative 

review of adverse decisions by the BLM. 

E.g., 43 CFR 3165.3(b). Issues of 

standing to participate in an 

administrative review or appeal of a 

BLM decision are beyond the scope of 

this rulemaking. 

Allow State Agencies To Regulate 

Several commenters suggested that 

the rule allow state oil and gas 

commissions to regulate hydraulic 

fracturing on Federal and tribal lands. 

Commenters believed that the BLM rule 

adds no value, and increases the layers 

of approval necessary to develop on 

Federal and tribal land. Other 

commenters stated that BLM rules 

duplicate state rules, and that because 

the states adequately protect and 

manage hydraulic fracturing, the BLM’s 

rules are unnecessary, add costs and 

burdens for compliance, and present 

regulatory inconsistencies when 

enforced alongside state rules. Several 

commenters said that hydraulic 

fracturing should be regulated at the 

state level because implementing a 

national rule would be unworkable due 

to the widely varying geology and 

techniques used from region to region. 

Other commenters recommended that in 

those states which already have an 

established regulatory process for 

hydraulic fracturing, operators should 

automatically be exempt from this rule. 

The BLM did not revise the rule as a 

result of these comments. The BLM 

recognizes that many states have made 

efforts to update their hydraulic 

fracturing regulations in recent years, 

but those regulations continue to be 

inconsistent across states. Further, those 

state rules may not apply to Indian 

lands. The rule will establish a 

consistent standard across Federal and 

Indian lands and fulfill BLM’s 

stewardship and trust responsibilities. 

In addition, the BLM is not allowed to 

delegate its responsibilities to the states. 

The BLM has worked diligently to 

reduce the compliance burden on 

operators, and will continue to work 

with the states and tribes to develop 

cooperative agreements to help align 

hydraulic fracturing regulations at the 

state, Federal, and tribal levels. 

Although no changes to the rule were 

made as a result of these comments, 

final section 3162.3–3(k) establishes a 

process for state or tribal variances, if 

the BLM determines that certain state or 

tribal rules meet or exceed the 

objectives of this rule. 

Several commenters objected to the 

use of state regulations. Commenters 

believed that state regulations were 

uneven and inconsistent, which could 

present problems for implementation 

and enforcement of the rule. The BLM 

did not revise the rule as a result of 

these comments. The rule applies on all 

Federal and Indian lands. 

Some commenters urged the BLM to 

defer to state regulations that are more 

stringent in protecting resources than 

this rule. All state laws apply on Federal 

lands, except those that are preempted 

by Federal law. This rule does not 

preempt any more stringent state or 

tribal law. Operators on Federal leases 

must comply both with this rule and 

any applicable state requirements, just 

as they already must comply with both 

BLM rules and state rules on a variety 

of drilling and completion issues. For 

example, if a state law required 

recovered fluids to be held in aboveground tanks, the BLM would not 

approve an application to use a lined 

pit. 

Some commenters objected to what 

they perceived as a suggestion that 

states do not have adequate regulatory 

authority. Those commenters are 

mistaken as to the BLM’s intent. This 

rule is not about state regulatory 

programs. It is about the Secretary 

fulfilling her obligations under the 

statutes that assign to her stewardship 

over public lands and trusteeship over 

Indian lands. 

Approve Service Companies 

Several commenters asked that the 

BLM regulate service companies. The 

commenters sought a list of ‘‘approved’’ 

service companies that would constitute 

the only eligible service companies who 

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could operate on Federal and Indian 

land and so that operators would not be 

compelled to submit chemical 

disclosure records to a BLM authorized 

officer. The BLM did not revise the rule 

because of these comments. The BLM 

believes the appropriate approach is to 

establish regulations that would apply 

to any service company selected by the 

operator rather than limiting the specific 

service companies that operate on 

Federal and Indian lands. 

Ban or Restrict Hydraulic Fracturing 

Many commenters asked that the BLM 

ban hydraulic fracturing, unless the 

chemicals used in hydraulic fracturing 

can be contained. The BLM did not 

revise the rule as a result of these 

comments. The goals of the rule include 

groundwater protection, wellbore 

integrity, and chemical disclosure. 

Chemical management, containment, 

and public disclosure are core purposes 

behind the regulation, and the BLM 

fully intends to contain chemicals used 

in hydraulic fracturing through this 

rule. 

Numerous commenters called for a 

moratorium or permanent ban on 

hydraulic fracturing on Federal and 

tribal lands. The BLM did not revise the 

rule as a result of these comments. The 

BLM has a responsibility under the 

FLPMA to act as a steward for the 

development, conservation, and 

protection of Federal lands, by 

implementing multiple use principles 

and recognizing, among other values, 

the Nation’s need for domestic sources 

of minerals from the public lands. A ban 

or moratorium would not satisfy the 

BLM’s multiple-use responsibilities 

under the FLPMA when regulations can 

adequately reduce the risks associated 

with hydraulic fracturing operations. 

Similarly, hydraulic fracturing 

operations on Indian lands result in 

substantial benefits to tribes and to 

individual Indians. By updating the 

requirements for hydraulic fracturing, 

this rule protects usable water on Indian 

lands without a ban or moratorium that 

could reduce royalty payments and 

employment. The BLM understands the 

risks and the environmental impacts of 

hydraulic fracturing operations, and the 

BLM believes that those risks and 

impacts can be managed by the rule. 

The rule will provide adequate 

assurance that hydraulic fracturing 

operations on Federal and Indian lands 

will continue to provide the Nation with 

domestically produced oil and gas and 

at the same time protect public lands 

and trust resources. 

Many commenters asked that the rule 

require minimum setback distances for 

hydraulic fracturing operations. Some 

commenters requested setbacks from 

sensitive areas, including conservation 

areas, areas of critical environmental 

concern, wilderness and roadless areas, 

wild and scenic river corridors, surface 

waters, drinking water supplies, homes, 

schools, hospitals, other buildings, and 

recreation areas. Some commenters 

proposed setback distances ranging from 

1,000 feet to half a mile. No revisions 

were made to the rule in response to 

these comments. 

The BLM has processes in place to 

ensure protection of sensitive areas. For 

example, the BLM has rules at 43 CFR 

3100.0–3(a)(2)(iii) that prohibit the 

leasing of Federal minerals beneath 

incorporated cities, towns, and villages, 

which is where the majority of homes, 

schools, hospitals, and other buildings 

are located. In addition, during 

development of a Resource Management 

Plan (RMP), the BLM identifies areas 

needing protection as areas closed to 

leasing or areas open to leasing, but 

with stipulations that limit or prohibit 

surface occupancy. Other sensitive areas 

are protected by seasonal and controlled 

surface use restrictions that are also 

developed during the land use planning 

process. When specific drilling 

proposals are received, the BLM 

conducts onsite inspections, which 

identify any sensitive areas and/or 

occupied dwellings. As part of the 

NEPA review for the specific proposal, 

the BLM then develops proper 

mitigation measures to protect these 

areas. Mitigation could include moving 

the well location and including sitespecific conditions of approval (COAs). 

In addition, if unnecessary or undue 

degradation impacts are identified (for 

public lands), or unacceptable impacts 

(on Indian lands), which cannot be 

mitigated, the BLM may deny the 

proposal. Through existing regulations, 

the RMP process, and the subsequent 

site-specific analyses, the BLM has 

measures in place to ensure protection 

of sensitive areas, drinking water 

supplies, and occupied buildings. 

Furthermore, state set-back 

requirements would normally apply on 

Federal lands, and tribal set-back 

requirements would apply on tribal 

lands (see also existing section 3162.3– 

1(b)). Minimum setbacks are more 

effective when they are determined and 

set at a site-specific level rather than in 

a nationwide rule because the unique 

circumstances of each drill site can be 

considered. Since setback requirements 

are already addressed in existing 

regulations and internal processes and 

policy, minimum setback distances are 

not necessary in this rule. 

Cooperative Agreements 

Several commenters asked that the 

BLM pursue cooperative agreements 

with states in order to establish more 

local control over hydraulic fracturing. 

Generally, the commenters believed that 

states have enhanced knowledge of the 

hydrological and geological conditions 

of their local oil and gas resources. The 

BLM did not make any rule changes 

based on these comments. The BLM 

intends to continue to pursue 

memoranda of understanding with 

states, and encourage further 

cooperation at the BLM State and field 

office level. The BLM cannot, however, 

delegate its stewardship responsibility 

to state or local officials, as some 

commenters suggested. The BLM must 

make the final decisions provided by 

statutes and regulations concerning 

operations on Federal lands and Indian 

lands. However, the BLM expects that 

by cooperatively working with states 

and through the variance process to 

appropriately consider state and tribal 

law and rules so as to reduce regulatory 

redundancies and compliance burdens. 

Some commenters asserted that the 

rule should include a formal 

memorandum of understanding 

mechanism whereby state approval of 

hydraulic fracturing operations would 

constitute BLM approval. No statute 

authorizes the BLM to delegate its 

responsibilities to states. The rule 

provides for statewide variances that 

could result in aligning state and BLM 

requirements to reduce compliance 

burdens for operators while assuring 

that resources in and on public lands 

are protected. 

Compliance With Other State and 

Federal Laws 

One commenter asked that the BLM 

include a statement in this rule 

requiring operators to comply with 

other Federal laws and with state laws. 

Section 3162.3–3(i)(8)(i) of this rule 

already requires that the operator certify 

that the hydraulic fracturing fluid 

constituents complied with all Federal, 

state, and local laws, rules, and 

regulations, in addition to other 

certifications. In addition, the BLM’s 

Federal oil and gas lease form requires 

the lessee to comply with all applicable 

laws, and that includes other Federal 

and state and local laws, rules, and 

regulations. That requirement is 

repeated in the existing regulations at 

sections 3162.1(a) and 3162.5–1(a). No 

revisions to this rule were made as a 

result of this comment because the 

commenters concern is already 

addressed in the rule and other BLM 

regulations. 

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Ensure Chemicals Are Safe 

A commenter suggested that the BLM 

require all chemicals used in hydraulic 

fracturing on Federal and Indian lands 

to be proven safe by an independent 

third party, or otherwise banned from 

use. The BLM did not revise the rule in 

response to this comment. The 

emphasis of this rule is to ensure that 

hydraulic fracturing fluid is confined to 

the intended zone and does not 

contaminate usable water zones, and 

that recovered fluids do not contaminate 

surface or ground water. Though this 

comment is beyond the scope of this 

rule, the BLM encourages the use of 

safer chemicals. Developing and using 

safer chemicals in all stages of hydraulic 

fracturing activities can help minimize 

potential environmental and health 

concerns while promoting greater public 

confidence. 

Need for the Rule 

Numerous commenters said that the 

rule disrupts the balance between 

environmental protection and energy 

development. The commenters stated 

that the rule would negatively affect 

jobs, revenue, and effective government. 

The BLM did not revise the rule as a 

result of these comments. The BLM 

evaluated these concerns as part of its 

economic analysis and found the 

impacts to be nominal in relation to 

current overall costs of drilling 

operations. The economic analysis is 

available upon request. 

Several commenters stated that 

operators currently submit information 

regarding casing and cementing 

programs as part of the existing APD 

process under Onshore Order 1. The 

commenters stated that the existing 

regulatory program already ensures well 

integrity, thereby making the provisions 

in the supplemental proposed rule 

unnecessary. The BLM did not revise 

the rule as a result of these comments. 

While the APD process does include 

many similar components regarding 

casing and cementing specifics related 

to well construction, this rule addresses 

specific hydraulic fracturing operational 

aspects to verify the integrity of the 

casing that existing rules do not address. 

Several commenters said that the rule 

is unnecessary and offers no change to 

the existing situation. The commenters 

indicated that the rule does not increase 

safety or transparency, and the 

supplemental proposed rule offered no 

solution. The BLM disagrees and did 

not make changes to the rule as a result 

of those comments. The BLM believes 

that compliance with these rules will 

increase transparency of the hydraulic 

fracturing approval process and provide 

a means for disclosure to the public of 

the fluids utilized in the hydraulic 

fracturing process. 

Several commenters said that the 

BLM had no reason to promulgate the 

regulations because there was no 

evidence that hydraulic fracturing 

operations have caused contamination 

of groundwater. The BLM disagrees. The 

need to assure that hydraulic fracturing 

fluids are isolated from surface waters, 

usable groundwater, and other wells is 

clear. The BLM also notes that those 

commenters’ arguments would apply 

equally to state regulations, which the 

same commenters champion. The final 

rule is not revised in response to those 

comments. 

Several commenters stated that the 

rule is unnecessary because it codifies 

common industry practice which has 

been successful in preventing 

groundwater contamination. The BLM 

did not make any changes to this rule 

as a result of these comments because 

the BLM has the responsibility of 

ensuring for the public and tribes that 

specific minimum standards are 

adhered to, and does not depend upon 

voluntary compliance. 

Several commenters requested that 

the BLM wait for EPA to complete its 

study of hydraulic fracturing and its 

potential impact on drinking water 

resources before promulgating a rule. 

The BLM does not believe it is 

necessary to wait for the EPA study to 

implement requirements that will help 

ensure the protection of water resources 

and the environment. Nothing prevents 

the BLM from updating its hydraulic 

fracturing regulations in light of a 

finalized EPA study. However, it is 

necessary to have adequate 

requirements in place without further 

delay. No revisions to the rule were 

made in response to this comment. 

Implementation or Grandfathering 

Many commenters asked whether the 

rule would apply to existing wells and 

requested that certain requirements be 

waived for those wells. The BLM agrees 

that the rule needs clarity on how it will 

address existing wells and added a table 

in section 3162.3–3(a) to specify which 

section of the rule would apply to 

which activity and when. Groundwater 

protection remains one of the principal 

reasons for applying the rule to all 

wells, existing or new. The BLM 

recognizes, however, that it may be 

impossible for an operator of an existing 

well to comply with all requirements of 

the rule. An example of this would be 

the requirements in section 3162.3– 

3(e)(1)(i) to monitor the casing and 

cementing operations, because the 

casing and cementing activities would 

have already occurred. Although most 

responsible operators retain that 

monitoring data and will be able to 

submit it to the BLM, not all of the data 

has been required by existing 

regulations. To comply with this section 

for existing wells, section 3162.3– 

3(e)(1)(ii) requires that the operator 

submit documentation demonstrating 

that an adequate cement job was 

achieved for all casing strings designed 

to isolate usable water, and provides 

that the BLM may require additional 

testing, verification, or other measures 

necessary to assure that the well will 

withstand hydraulic fracturing 

operations. 

Several commenters suggested a 

phased or delayed implementation of 

the rule to give industry time to comply 

with the provisions of the new rule. One 

commenter requested a 180-day 

implementation period, instead of the 

60-day implementation period required 

by statute and executive order 

(Congressional Review Act (5 U.S.C. 

801–808) and Executive Order 12866). 

The BLM agrees that a longer 

implementation time is required given 

the complexity of the rule, the potential 

impacts of the rule on industry, the 

coordination needed with other entities, 

such as the GWPC for FracFocus, and 

for the development of internal training 

and policy. However, the public also 

expects new requirements for hydraulic 

fracturing to be implemented in a timely 

manner. Therefore, the final rule will be 

effective 90 days after publication in the 

Federal Register. Outreach to industry 

and the public is also anticipated during 

this implementation period. The table in 

section 3162.3–3(a) provides for an 

additional 90 day phase-in of the 

requirement to obtain the BLM’s prior 

approval under limited circumstances. 

No well (existing or otherwise) 

proposed for hydraulic fracturing after 

June 24, 2015 will be exempt from 

paragraphs (b), (e), (f), (g), (h), (i), and 

(j), the substantive requirements of the 

rule. 

One commenter requested that the 

term ‘‘New Well’’ be added to the 

definitions section. The commenter 

recommended the following definition: 

‘‘New well means an oil and gas well for 

which surface casing was set and 

cemented on or after 60 Days after 

publication in the Federal Register.’’ 

The commenter was concerned that 

existing wells could not meet the 

cement monitoring and CEL 

requirements in the supplemental 

proposed rule. The commenter also 

suggested the cementing monitoring and 

CEL requirements should only apply to 

new wells as defined. The BLM 

recognizes the potential challenges with 

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the cement monitoring requirements on 

existing wells. The BLM, however, did 

not include a definition for ‘‘New Well’’ 

in the rule. Instead, final section 

3162.3–3(a) of the rule clarifies that for 

wells drilled prior to the effective date 

of the rule, the operator must provide 

the documentation required in 3162.3– 

3(e) or demonstrate to the authorized 

officer that the casing and cement have 

isolated usable water zones. 

Ban Diesel 

Several commenters asked that the 

BLM completely ban the use of diesel 

fuel in hydraulic fracturing fluids. The 

BLM did not make changes as result of 

these comments. Congress has 

authorized regulation of the use of 

diesel fuels in hydraulic fracturing fluid 

by the Environmental Protection Agency 

(EPA), Underground Injection Control 

(UIC) Program. The EPA has provided 

technical guidance for protecting 

underground sources of drinking water 

(USDWs) from potential endangerment 

posed by hydraulic fracturing 

operations by requiring a permit under 

the UIC program where diesel fuels are 

used. See EPA Underground Injection 

Control Program Guidance # 84 for 

issues concerning diesel fuels during 

hydraulic fracturing operations (79 FR 

8451). If, however, a state (on Federal 

lands) or a tribe (on tribal lands) 

prohibited the use of diesel, this rule 

would not ordinarily preempt such 

regulations. 

Bonding 

Many commenters requested that the 

BLM increase liability bonds to account 

for the increased risk caused by 

hydraulic fracturing operations. The 

BLM did not revise the rule as a result 

of these comments. Existing section 

3104.5(b) authorizes the BLM to adjust 

bond amounts to appropriately reflect 

the level of risk posed by an oil and gas 

operation. The BLM may increase the 

bond amount if there is a history of 

previous violations, if there are 

uncollected royalties due, or if the total 

cost of plugging existing wells and 

reclaiming lands exceeds the present 

bond amount based on the estimates 

determined by the authorized officer. 

The BLM believes that it has authority 

under existing regulations to adjust 

bond amounts to address any increased 

liability that may be present as a result 

of hydraulic fracturing operations. The 

BLM will make a liability determination 

for hydraulic fracturing on a case-bycase basis and increase the bond amount 

as necessary. 

Prior Approval for All Changes 

Many commenters stated that the rule 

should be modified to require prior 

approval for all significant changes to 

the proposed hydraulic fracturing plan. 

The commenter stated that the 

regulation only requires that the 

operator provide notice to the BLM after 

the hydraulic operations are complete. 

The BLM did not revise the rule as a 

result of these comments. The 

requirements that the commenter is 

referencing are specific to hydraulic 

fracturing operations that did not 

proceed as planned. Any change of 

plans from any approved permit must 

be submitted to the BLM for a new 

approval. This is the same requirement 

for changes to all authorizations for oil 

and gas operations, including APDs and 

Sundry Notices. 

One commenter requested that the 

BLM establish criteria that would rise to 

the level of a ‘‘change in scope’’ that 

would necessitate the operator filing a 

subsequent Form 3160–5 Sundry Notice 

in the event of a change or deviation 

from the previously approved hydraulic 

fracturing operation. Too many possible 

scenarios exist to develop criteria that 

would address all issues that could 

arise. The BLM expects the operator to 

follow the approved plan along with 

any COAs. The BLM, however, 

recognizes that the operator may make 

minor changes in the design criteria 

prior to the hydraulic fracturing 

operations. This recognition is already 

acknowledged in the rule. Many of the 

items required in the permit application 

can be estimates (see final section 

3162.3–3(d)). For example, the rule 

requires estimated pump pressures and 

the estimated total volume of fluid to be 

used. Slight deviations from these 

estimates would not trigger the need for 

a new Sundry Notice. Those items that 

cannot be estimated, however, such as 

the location of the water supply or the 

method of handling the recovered 

fluids, would have to be disclosed on an 

additional Sundry Notice requesting 

changes to the original approval. No 

revisions to the rule were made as a 

result of this comment. 

Mitigation Measures 

Many commenters asked that the rule 

require a number of specific actions 

from the operator such as: 

• The installation of air and water 

monitoring equipment on all hydraulic 

fracturing operations. The commenters 

stated that more comprehensive 

monitoring, including air and 

groundwater quality monitoring, could 

help build a knowledge base regarding 

hydraulic fracturing and its effects on 

the environment; 

• Dust abatement on county roads; 

• The power washing and inspection 

of all vehicles entering a well site to 

prevent non-native invasive plant 

species from becoming established; 

• The installation of sound 

dampening devices; 

• Prohibiting the use of jake (engine) 

brakes on trucks operating near 

residential areas; 

• Provisions to control stormwater 

runoff; 

• Capturing or controlling greenhouse 

gas emissions during hydraulic 

fracturing operations; and 

• The prohibition of flaring in 

sensitive areas. 

The BLM did not make any changes 

to the rule as a result of these 

comments. First, the requested changes 

are outside the scope of this rule, which 

is specific to hydraulic fracturing 

operations. With the exception of the 

installation of air and water monitoring 

equipment, all of the other requested 

changes would apply to oil and gas 

operations in general and are not unique 

or specific to hydraulic fracturing or 

appropriate to address in a hydraulic 

fracturing rule. Second, the BLM 

believes that it is not appropriate to 

require specific mitigation measures in 

a national rule of general applicability. 

Requiring specific actions such air 

monitoring, dust abatement, or power 

washing of vehicles is best left to the 

discretion of the local BLM offices, 

determined through NEPA analysis on a 

case-by-case basis and applied as lease 

stipulations, and conditions of approval 

in permits to drill, or through best 

management practices that operators 

may propose in their APDs. The rule 

must allow for some degree of flexibility 

to accommodate the wide range of 

geologic and environmental conditions 

encountered on Federal and Indian 

leases. If water quality or other impacts 

are anticipated due to hydraulic 

fracturing operations, the BLM would 

then develop mitigation measures, such 

as water quality monitoring, dust 

emission control, and any other relevant 

actions on a case-by-case basis. These 

requirements will be included as 

specific conditions of approval (COA) in 

the drilling permit to the extent 

consistent with the lease rights. 

‘‘Frack Hits’’ 

Several commenters expressed 

general concern over ‘‘frack hits’’ (i.e., 

unplanned interconnectivity of wells 

during a hydraulic fracturing operation 

through the underground formations 

between the well undergoing a 

fracturing operation and an existing 

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well), and that the NOI review process 

should include an area of review to 

identify nearby wells and fractures, in 

addition to prescribing reporting, 

evaluation, and corrective actions for 

frack hits. 

The BLM revised the rule as a result 

of these comments. As provided in this 

final rule, hydraulic fracture design, 

including estimated fracture length and 

direction data, are required to be 

submitted as part of the APD or NOI. In 

addition, the final rule requires the 

operator to provide a map showing the 

extent of the fractures along with all 

known wellbore trajectories within onehalf mile of the well that is proposed to 

be fractured. One purpose of fracture 

design data is to avoid potential 

intersection between fractured pathways 

to existing nearby wellbores. These data 

will be reviewed during the review 

process for hydraulic fracturing 

approval. The provisions of Notice to 

Lessees and Operators of Onshore 

Federal and Indian Oil and Gas Leases 

(NTL–3A), March 1, 1979, (44 FR 2204) 

and other regulations already contain 

operator obligations for reporting, 

evaluation, and corrective actions in the 

event of an environmental release. 

Enforcement provisions for releases into 

the environment involving Federal or 

tribal leases already exist in the 

regulations and are outside the scope of 

this rulemaking. 

Independent Review of Hydraulic 

Fracturing 

Several commenters stated that the 

rule should be modified to establish an 

independent review of hydraulic 

fracturing proposals. The BLM did not 

revise the rule as a result of these 

comments. The BLM has the necessary 

expertise to properly review hydraulic 

fracturing proposals. 

Public/Landowner Participation 

Several commenters stated that the 

rule should require notice to 

landowners, communities, and other 

stakeholders when hydraulic fracturing 

is proposed. Commenters said that the 

rule should require notice to parties 

located at various distances from 500 

feet to 10 miles away from the hydraulic 

fracturing operation. The BLM did not 

revise the rule as a result of these 

comments. Public notice of Federal oil 

and gas operations is already provided 

to both the public and nearby 

landowners. By statute and regulations, 

notice of Federal APDs are publicly 

posted in BLM field office public rooms 

for a minimum of 30 days before the 

BLM issues a permit to drill (see 

existing section 3162.3–1(g)). Some field 

offices also make this information 

available on the field office Web site. 

Furthermore, the BLM is working on 

improvements to make additional 

information available on a Web site for 

all Federal APDs in the near future. The 

information would include the operator 

name, well name and number, surface 

location legal land description, the date 

the BLM received the application, the 

date the BLM approved the application, 

the date the well was spudded, and the 

date the well was completed. 

Additionally, surface owners of split 

estate lands are invited to attend the 

onsite inspection before an APD is 

approved, and other agencies and 

interested parties can request to attend 

the onsite well inspection. Also, the 

APD surface use plan of operations lists 

all wells and water wells within 

prescribed distances from the proposed 

wells, which provides additional 

information to the public about 

potential concerns. Although 

stakeholders could assume that any 

proposed well would be hydraulically 

fractured, the BLM will be exploring 

ways to provide additional public notice 

of proposed hydraulic fracturing 

operations. Information that would be 

required to be submitted as part of this 

rule will be made available to the 

public, consistent with the requirements 

of Federal law. Note, though, that the 

rule does not preempt notification 

requirements of states (on Federal lands) 

or tribes (on tribal lands). 

Several commenters stated that the 

rule should be modified to provide for 

stakeholder participation in the 

permitting process for hydraulic 

fracturing operations. The BLM did not 

revise the rule as a result of these 

comments. The BLM already provides 

numerous opportunities for stakeholder 

participation during the Federal oil and 

gas leasing process as well as the APD 

process on Federal lands and 

stakeholders are specifically invited to 

participate during the NEPA process. 

Ensuring Wellbore Integrity 

Several commenters stated that 

Onshore Order 2 is inadequate to ensure 

wellbore integrity during hydraulic 

fracturing operations. According to 

these commenters, the BLM needs more 

requirements specific to casing 

centralization, intermediate and 

production casing standards, cement 

types, cement compressive strength, 

ensuring proper wellbore condition 

prior to cementing, and ensuring a static 

wellbore during cementing operations. 

The BLM did not revise the rule as a 

result of these comments. Onshore 

Order 2 provides uniform national 

standards for the minimum levels of 

performance expected from operators 

when conducting drilling operations, 

including casing design, casing 

centralization, and cement compressive 

strength. The BLM reviews each drilling 

proposal to ensure that operations will 

meet these minimum standards. If the 

BLM’s review determines that 

additional requirements regarding 

casing centralization, cement types, 

cement compressive strengths, etc., are 

necessary for wellbore integrity or 

isolation of usable water, the BLM can 

require the operator to modify its 

proposal or add COAs. The BLM 

believes that the requirements for well 

drilling, casing, or cementing in 

Onshore Order 2 along with the new 

requirements established by this rule are 

sufficient to assure that wellbores can 

withstand hydraulic fracturing 

operations. 

Seismicity 

Several comments stated that the rule 

should be modified to limit hydraulic 

fracturing activities in those areas with 

seismic zones. The BLM did not revise 

the rule as a result of these comments. 

The research on the phenomena of 

induced seismicity from hydraulic 

fracturing operations is still ongoing and 

inconclusive. For hydraulic fracturing 

operations proposed in seismically 

active areas or when the BLM 

determines through the internal and 

public scoping process that seismic 

impacts are an issue, risks of induced 

seismicity would be evaluated through 

the NEPA analysis, including analysis of 

the proposed drilling and fracturing 

operations. These final regulations also 

require submittal of additional geologic 

information prior to hydraulic fracturing 

to help further that review. 

Tracers 

Several commenters stated that the 

rule should be revised to require tracer 

surveys in production and injection 

wells. The commenters indicated that if 

tracer efficacy could be validated, then 

the BLM should require its use. One 

commenter suggested that some of the 

constituents in flow back fluid could be 

used for tracers. The BLM did not revise 

the rule as a result of these comments. 

One of the rule’s major emphases is the 

prevention of groundwater 

contamination from hydraulic fracturing 

operations through ensuring wellbore 

integrity and the isolation of usable 

water zones. Additionally, while the 

BLM believes that tracers may have 

value in certain situations, their overall 

effectiveness is questionable due to 

dilution and detection issues. These 

limitations render tracer surveys 

inappropriate for universal application 

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9American Petroleum Institute (API) guidance, 

‘‘Hydraulic Fracturing Operations-Well 

Construction and Integrity Guidelines, First Edition, 

October 2009.’’ 

for all hydraulic fracturing operations 

on Federal or Indian lands. 

Baseline Monitoring 

Numerous commenters asked that the 

BLM require baseline air and water 

monitoring prior to hydraulic fracturing. 

The commenters stated that without 

baseline air and water quality data, it 

would be impossible to prove (or 

disprove) that hydraulic fracturing 

caused changes in air or water quality. 

Several commenters noted that the API 

guidance document on hydraulic 

fracturing (HF–1) recommends baseline 

water quality monitoring of both surface 

and groundwater prior to hydraulic 

fracturing. 

The BLM agrees that baseline air and 

water quality data and monitoring are 

good policies with benefits for land 

managers, the public, and the oil and 

gas industry, and fully endorses the API 

guidance with respect to baseline water 

monitoring. The BLM supports and 

encourages baseline testing and 

monitoring, and will require those 

activities on a case-by-case basis where 

appropriate, but is not requiring 

baseline monitoring in this nationwide 

rule for several reasons. First, there is 

such a wide variety of hydrogeological 

conditions that it would be unworkable 

to establish a single requirement for 

baseline water monitoring for all 

Federal and Indian lands. For example, 

some locations may not have surface or 

ground water resources, while other 

locations may have a mix of different 

types of water resources. 

Second, there are many places where 

the BLM either does not manage the 

surface above the leased minerals, or the 

locations where baseline testing and 

monitoring would be necessary or most 

useful would be off of BLM-managed 

land. The BLM has no authority to 

require air or water quality monitoring 

on non-Federal lands, and limited 

authority on non-Federal surface estates 

(‘‘split estates’’). If the final rule were to 

require baseline testing and on-going 

monitoring, it would need to have so 

many exceptions that it would be 

confusing and of limited value. 

Given the fact that the BLM cannot 

rationally and consistently implement 

baseline monitoring requirements, no 

revisions to the rule were made as a 

result of these comments. Nonetheless, 

analysis of potential impacts to both air 

and water quality are common elements 

of any NEPA review that the BLM 

prepares on proposals for drilling and 

hydraulic fracturing operations. If air or 

water quality impacts are anticipated, 

then, if not already part of the proposed 

operation, the BLM could require 

mitigation measures to address those 

impacts. These include baseline testing 

and monitoring that would be 

developed on a case-by-case basis taking 

into account local hydrogeologic or 

airshed factors, plans for field 

development, land ownership, and 

existing data and monitoring programs 

required or implemented by other 

agencies. These mitigation measures 

would be imposed as a condition of the 

BLM’s approval for a given project. 

There are a number of cases where the 

BLM has required the baseline testing 

and monitoring of air and water 

resources as part of its decision to 

approve the development of oil and gas 

resources. For example, the Records of 

Decision (ROD) for the Pinedale 

Anticline Project Area Environmental 

Impact Statement (EIS) (see Appendix 

A–3 at http://www.blm.gov/wy/st/en/

info/NEPA/documents/pfo/

anticline.html), the Pinedale Anticline 

Project Area Supplemental EIS (see 

Chapter 4 at http://www.blm.gov/wy/st/ 

en/info/NEPA/documents/pfo/anticline/

seis.html), and the Greater Natural 

Buttes Final EIS (see Appendix C at 

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

planning/nepa.html) include 

requirements for oil and gas operators to 

test/identify baseline air and water 

(surface and subsurface) conditions, and 

monitor trends in resource conditions 

throughout the project. Furthermore, if 

the Federal surface management agency 

(such as the U.S.D.A. Forest Service) 

required air or water monitoring as part 

of the surface use plan, then those 

requirements would be enforceable. 

Some commenters said that BLM 

could require operators to obtain 

permission to test water on non-Federal 

lands. Although states’ or tribal police 

powers may authorize such 

requirements, the BLM’s statutory 

authority does not extend to nonfederal, non-Indian lands, absent a 

threat to Federal resources. We therefore 

decline to revise the rule as suggested. 

Other comments recommended that 

the BLM require baseline monitoring of 

soil, plants, human sickness, and 

environmental degradation before, 

during, and after hydraulic fracturing. 

Additionally, one commenter asked that 

the BLM provide landowners 

information on how to test their water 

to document baseline conditions. The 

BLM did not revise the rule as a result 

of those comments. Similar to the 

recommendation in the API Guidance 9

(section 10.2) for conducting a baseline 

assessment once the location for a well 

has been selected and before it is 

drilled, as part of the NEPA analysis, the 

BLM examines the baseline condition of 

the site, evaluates the potential effects of 

the proposed operation, and suggests 

mitigation and monitoring needs when 

necessary. As with baseline water 

monitoring, the BLM could require 

monitoring of resources on Federal 

lands, and with the surface owner’s 

consent on split-estate lands, as a sitespecific mitigation measure based on an 

environmental analysis prepared under 

NEPA. Although the BLM has expertise 

in management of Federal lands, 

monitoring the health of persons or of 

natural resources on non-Federal lands 

is entrusted to other local, state, tribal 

or Federal agencies with appropriate 

authority and expertise. Similarly, this 

rule does not attempt to advise 

landowners or tenants on how to test 

their water. Other agencies and private 

consultants have the expertise to 

provide that advice. 

Water Use 

Several commenters requested that 

the rule address the potential stresses on 

local fresh water supplies. The 

commenters expressed concern that 

local fresh water supplies will be 

diminished by the demand for water for 

hydraulic fracturing. Some commenters 

suggested placing restrictions on the use 

of local fresh water and requiring the 

use of non-fresh water sources or 

recycled water to help reduce potential 

impacts to local fresh water. Other 

commenters requested the rule include 

restrictions on water usage. The BLM 

understands the concerns raised by the 

commenters. The BLM encourages 

operators to treat and recycle the water 

returned after performing hydraulic 

fracturing along with the water 

produced from the formation. In fact 

many operators on public lands are 

currently considering options of using 

produced water or recycled water for 

their hydraulic fracturing operations. 

The BLM, however, does not have 

regulatory authority over the use of local 

fresh water. State and tribal 

governments, through administration of 

water rights and permitting water wells, 

regulate water usage. Existing state and 

tribal laws require operators to obtain 

the proper permits and rights to use 

surface and groundwater. No revisions 

to rule were made as a result of these 

comments. 

Some commenters expressed concern 

about the lack of groundwater use 

regulation in the rule. Commenters 

recommended that the rule include an 

assessment of water availability, 

provisions for reducing water use 

during droughts, and require that 

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companies monitor the level of the 

water table. Other comments suggested 

that the rule provide for protection of 

over-appropriation of water and 

disclosure of water take that should 

occur prior to the start of hydraulic 

fracturing operations. All of these items 

are beyond the scope of this rule. States 

and tribes have regulatory authority 

over water usage. However, as a matter 

of course, the BLM requires the 

submission of information on water 

sources to assist the BLM in assessing 

the environmental effects of individual 

drilling operations. The NEPA process 

requires that Federal agencies assess the 

environmental impacts of their 

proposed actions to inform their 

decision-making and this includes 

effects on water resources. The 

information on water sources will be 

part of an environmental analysis of 

hydraulic fracturing operations. No 

revisions to the rule were made as a 

result of this comment. 

One commenter recommended 

operators should pay for monitoring 

wells when there is suspected 

contamination. Other commenters 

recommended that the rule be 

strengthened by requiring the operator 

to physically replace any water supply 

that is contaminated. These 

recommendations are beyond the scope 

of this rule. The goal of the rule is to 

ensure proper wellbore construction 

and handling of produced fluids to 

prevent any contamination. If a 

situation arises where contamination 

from hydraulic fracturing operations is 

suspected, the BLM will work closely 

with states and tribes to determine the 

proper course of action. The proper 

course of action for any given situation 

will depend on the unique 

circumstances of that situation. No 

revisions to the rule were made as a 

result of this comment. 

Mandatory Recycling 

Some commenters asked that the rule 

include a requirement that some 

quantity of the water used in hydraulic 

fracturing operations must be recycled 

water. The commenters did not offer 

specific quantities. The BLM encourages 

operators to treat and recycle the water 

returned after performing hydraulic 

fracturing along with the water 

produced from the formation. Many 

operators are currently looking at 

options for using produced water and/ 

or recycled water for their hydraulic 

fracturing operations. However, 

mandating the recycling of water is 

outside of the scope of this rule. No 

revisions to the rule were made as a 

result of these comments. 

Breach of Contract 

Some commenters asserted that the 

rules would make oil and gas operations 

uneconomic, and that would result in 

Federal liability for a breach of the 

lease. Federal oil and gas leases clearly 

provide that the lease rights are subject 

to all current and future regulations. 

The rule is an operational regulation 

and does not change any financial term 

of any Federal or Indian lease. The BLM 

does not expect the rule to dissuade 

operators from drilling in geologically 

promising areas. Lessees and operators 

routinely decide not to drill on leases 

found to be geologically unpromising or 

uneconomic, but the BLM is not 

required to waive drilling and 

completion regulations to improve 

profitability. 

Tribal Issues 

Some commenters asserted that the 

rule would be a breach of trust on 

Indian lands. The BLM disagrees. As all 

the other provisions of 43 CFR part 

3160, the rule protects trust resources to 

the same extent that it protects 

resources in or on Federal lands. The 

commenters did not identify any 

provision of the Constitution, or a 

treaty, statute, or regulation that the rule 

violates. One tribe in its comments 

proposed 10 specific conditions of 

approval that it wanted to apply to 

hydraulic fracturing operations on its 

tribal lands. The BLM imposes 

conditions of approval on a case-by-case 

basis based on unique on-the-ground 

geologic, environmental, and 

operational circumstances. Specific 

conditions of approval are beyond the 

scope of this rulemaking and are 

inappropriate in a rule of general 

applicability. If hydraulic fracturing is 

proposed for specific tribal lands and 

the tribe proposes specific conditions 

for the BLM to apply, the BLM will 

consider the tribe’s proposal for that 

development. 

Some commenters said that the BLM 

has no authority under the FLPMA to 

promulgate regulations on Indian lands. 

The BLM agrees. The BLM’s authority to 

regulate oil and gas operations on 

Indian lands does not come from the 

FLPMA. The Act of March 3, 1909 (25 

U.S.C. 396), the Indian Mineral Leasing 

Act (IMLA) (25 U.S.C. 396d), and the 

Indian Mineral Development Act (25 

U.S.C. 2107) assign regulatory authority 

to the Secretary over Indian oil and gas 

leases on trust lands (except those 

excluded from the IMLA, i.e., the Crow 

Reservation in Montana, the ceded 

lands of the Shoshone Reservation in 

Wyoming, the Osage Reservation in 

Oklahoma, and the coal and asphalt 

lands of the Choctaw and Chickasaw 

Tribes in Oklahoma). The Secretary 

delegated to the BLM the authority to 

oversee oil and gas operations on Indian 

mineral leases through the Departmental 

Manual (235 DM 1.K.). The Bureau of 

Indian Affairs’ regulations provide that 

BLM’s operating regulations at 43 CFR 

part 3160 apply to oil and gas leases on 

trust and restricted Indian lands, both 

tribal and individually owned. See 25 

CFR 211.4, 212.4, and 225.4. 

Some commenters said that the 

FLPMA prohibits the BLM from 

exercising any part of the Secretary’s 

trustee responsibilities over Indian 

lands. On the contrary, the FLPMA 

expressly provides that the Director of 

the BLM ‘‘shall perform such duties as 

the Secretary may prescribe with respect 

to the management of lands and 

resources under [her] jurisdiction 

according to the applicable provisions 

of [the FLPMA] and any other 

applicable law.’’ 43 U.S.C. 1731(a). 

Indian trust and restricted lands and 

minerals are resources under the 

Secretary’s jurisdiction under applicable 

law. Therefore the delegation of 

operational oversight to the BLM of oil 

and gas development on Indian lands as 

exercised in this final rule is proper. 

Several commenters said that the 

BLM’s consultation process was not 

adequate. In light of statutory 

responsibilities and executive policies, 

including the Department’s Tribal 

Consultation Policy (Secretarial Order 

3317) and Executive Order 13175, the 

BLM attaches great importance to tribal 

consultation. During the proposed rule 

stage, the BLM initiated government-togovernment consultation with tribes on 

the proposed rule and offered to hold 

follow-up consultation meetings with 

any tribe that desired to have an 

individual meeting. In January 2012, the 

BLM held four regional tribal 

consultation meetings, to which over 

175 tribal entities were invited. 

Individual follow-up consultation 

meetings involved the local BLM 

authorized officers and management, 

including State Directors. After the 

publication of the initial proposed rule, 

tribal governments and tribal members 

were also invited to comment directly 

on the proposed rule. 

In June 2012, the BLM held additional 

regional consultation meetings in Salt 

Lake City, Utah; Farmington, New 

Mexico; Tulsa, Oklahoma; and Billings, 

Montana. Eighty-one tribal members 

representing 27 tribes attended the 

meetings. In those sessions, the BLM 

and tribal representatives engaged in 

substantive discussions of the proposed 

hydraulic fracturing rule. A variety of 

issues were discussed, including, but 

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not limited to, the applicability of tribal 

laws, validating water sources, 

inspection and enforcement, wellbore 

integrity, and water management. 

Additional individual consultations 

with tribal representatives took place. 

Consultation meetings were also held at 

the National Congress of American 

Indian Conference in Lincoln, Nebraska, 

on June 18, 2012, and at New Town, 

North Dakota on July 13, 2012. 

After publication of the supplemental 

proposed rule, the BLM again held 

regional meetings with tribes in 

Farmington, New Mexico, and 

Dickinson, North Dakota, in June 2013. 

Representatives from six tribes attended. 

The discussions included a variety of 

tribal-specific and general issues. One 

change resulting from those discussions 

is the re-drafting of paragraph 3162.3– 

3(k) to clarify that tribal and state 

variances are separate from variances for 

a specific operator. The BLM again 

offered to follow up with one-on-one 

consultations, and several such 

meetings were held with individual 

tribes. Several tribes, tribal members, 

and associations of tribes provided 

comments on the revised proposed rule. 

In March 2014, the BLM invited tribes 

to participate in another meeting in 

Denver, Colorado. Twelve tribal 

representatives attended the meeting. 

There was significant discussion of 

issues raised in the comments on the 

revised proposed rule. The BLM 

believes its tribal consultation efforts 

were thorough. 

Nonetheless, some commenters assert 

that the BLM failed to follow the stages 

of consultation set out in the 

Departmental consultation policy and 

Executive Order 13175. The BLM 

believes that it has complied with that 

Executive Order and with Secretarial 

Order 3317. The BLM understands the 

importance of tribal sovereignty and 

self-determination, and seeks to 

continuously improve its 

communications and government-togovernment relations with tribes. 

Some commenters said that the rule 

continued to apply the same 

requirements to operations on Indian 

lands as on Federal lands. They said 

that the BLM should promulgate 

different rules for Indian lands, citing as 

examples the authority of the BIA over 

cancellation of Indian leases, and 

ONRR’s royalty valuation criteria for 

operations on Indian lands. The BLM 

does not assert that implementing its 

operational regulations on oil and gas 

operations on Indian lands is the only 

possible way to carry out the Secretary’s 

trust responsibilities under the Indian 

mineral statutes cited earlier. 

Nonetheless, it is the means chosen by 

the Secretary and the BIA, and is more 

economic than creating a parallel set of 

regulations and regulatory personnel in 

the BIA. The BLM believes it is fulfilling 

its part of the Secretary’s trust 

responsibilities by requiring operations 

on Indian lands to meet the same 

standards as those on Federal lands. 

Some commenters urged the BLM to 

allow tribes to opt out of the final rule. 

A commenter also cited to BIA’s 

regulations that provide for a tribal 

constitution or charter issued under the 

Indian Reorganization Act of 1934, or 

resolution authorized by such 

constitution to supersede the 

regulations in 25 CFR part 211 (which 

includes 25 CFR 211.4). See 25 CFR 

211.29. That section, however, also 

includes a proviso that tribal law may 

not supersede the requirements of 

Federal statutes applicable to Indian 

mineral leases, and that the regulations 

in that part apply to tribal leases and 

permits that require the Secretary’s 

approval. The commenters have not 

explained why, among all the other 

requirements of 43 CFR part 3160, an 

opt-out should be provided for this rule. 

Some commenters said that the final 

rule should be ‘‘inoperative’’ on tribal 

lands once the tribe has demonstrated 

that its regulatory program is 

‘‘sufficient’’ to govern hydraulic 

fracturing operations. The Indian 

mineral leasing statutes previously cited 

do not authorize tribes to opt-out of the 

Secretary’s regulations, and, unlike 

some environmental statutes, do not 

authorize tribal ‘‘primacy.’’ 

Furthermore, the BLM has no way of 

terminating the Secretary’s trust 

responsibilities for hydraulic fracturing 

operations if a tribe were to opt out of 

having the BLM’s regulations apply on 

that tribe’s lands, or if the BLM failed 

to implement the final rule because a 

tribe was implementing its own 

program. 

Several commenters addressed the 

variance provision approvingly. Some 

urged the BLM to recognize tribal 

regulations. The BLM recognizes that 

some tribes have been proactive in 

regulating hydraulic fracturing on their 

lands. It is not the BLM’s intent to 

preempt tribal regulations. Commenters 

did not bring to the BLM’s attention any 

tribal regulation or lease provision that 

the final rule would preempt. In the 

absence of preemption, tribal law would 

apply to leases of tribal and individually 

owned Indian land in addition to the 

final rule. 

The variance provision of the rule 

allows the BLM, in cooperation with a 

tribe, to issue a variance that would 

apply to all wells within that tribe’s 

lands, or to specific fields or basins 

within those lands, if the State Director 

determines that the proposal meets or 

exceeds the objectives of the provision 

for which a variance is requested. A 

variance would not necessarily adopt 

tribal regulations as the Federal rule. 

However, a variance would, for 

example, be a way of doing such 

common-sense things as aligning 

reporting requirements of the two 

sovereigns, addressing unique 

geological conditions, or facilitating 

technological innovation, while 

maintaining the performance standards 

and adequate margins of protection 

provided in the final rule. 

Some commenters said that the 

variance provision does not comply 

with policies promoting tribal 

sovereignty, self-determination, and the 

Federal government’s trust 

responsibility. The BLM believes that 

the rule is consistent with the Federal 

government’s trust responsibility 

because it assures that Indian lands 

receive the same substantive protection 

as Federal lands, and that it promotes 

tribal sovereignty by facilitating 

coordination to achieve the goals of both 

sovereigns. By recognizing tribal 

regulations, it accords with tribal selfdetermination to the extent that could 

be expected from a rule governing 

hydraulic fracturing operations. 

A commenter stated that tribal 

variances should not be subject to 

public comment. The rule does not 

provide for public notice and comment 

on tribal variances and the rule is not 

revised as a result of this comment. 

Some commenters asked that the BLM 

provide more information about how to 

obtain contracts and funding under 

Public Law 93–638, the Indian SelfDetermination and Education 

Assistance Act of 1975, 25 U.S.C. 450 et 

seq., as amended. Implementation of 

Public Law 93–638 and its amending 

statutes is beyond the scope of this 

rulemaking, and is governed by 

regulations in Title 25 of the CFR. If a 

tribe wishes to apply for a contract to 

perform any of BLM’s functions under 

43 CFR part 3160, it should contact the 

BLM. 

Some commenters opposed the rule, 

or said that it should not apply on 

Indian lands, stating that it would 

increase operators’ costs, and thereby 

make Indian lands less attractive to the 

oil and gas industry, potentially 

resulting in reductions of revenue to the 

tribes. The rule would not render Indian 

lands more or less attractive than 

Federal lands. In reviewing the 

comments and preparing the final rule, 

the BLM has looked for ways to reduce 

costs and burdens for operators, and to 

focus on requirements that promote the 

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goals of assuring isolation and 

protection of usable water. As shown in 

the economic analysis, the costs of 

complying with the final rule on Federal 

or Indian lands will be a small 

percentage of an operator’s costs of 

drilling and completing a well. Those 

additional costs would be easily 

outweighed by revenues that operators 

might anticipate from a geologically 

attractive area. Tribes and their 

members will also benefit from the 

substantial increase in assurance that 

their usable water will be isolated and 

protected. 

Cost Recovery 

Some commenters supported the rule 

and suggested that the rule include a 

cost recovery fee for hydraulic 

fracturing approval and inspection. The 

BLM did not propose a separate cost 

recovery fee for hydraulic fracturing 

approval and inspection in the initial 

and supplemental proposed rules. 

Section 365 of the Energy Policy Act of 

2005 prohibits the Secretary from 

implementing a rulemaking that would 

enable an increase in fees to recover 

additional costs related to processing 

drilling-related permit applications and 

use authorizations until the end of fiscal 

year 2015. The BLM fully expects to 

process requests for hydraulic fracturing 

concurrently with the processing of 

drilling applications. The final rule does 

not include such fees, however, the 

BLM may address that in any future cost 

recovery adjustments. 

BLM’s Jurisdiction 

Some commenters asserted that the 

rule is beyond the Secretary’s 

jurisdiction because protection of 

surface waters and groundwaters are 

under the EPA’s jurisdiction, not the 

BLM’s jurisdiction. The BLM agrees that 

regulation of the quality of surface 

waters under the Clean Water Act, and 

the regulation of groundwater under the 

SDWA, are the duties of EPA and states 

and tribes. The requirements of this rule 

do not interfere with those programs. 

The rule does not address discharges to 

surface waters at all. The rule clarifies 

the existing definition of usable water to 

defer to state or tribal designations of 

aquifers as underground sources of 

drinking water or as exempted aquifers 

under the SDWA, so long as these 

designations are not inconsistent with 

the SDWA. 

Some commenters challenged the 

Secretary’s authority to regulate well 

construction and operation. Some 

claimed that the Secretary has no 

authority to disapprove or to require 

revisions to a hydraulic fracturing 

proposal. Some claim that the Secretary 

has no authority other than to lease 

lands and collect royalties. The BLM 

disagrees. The Secretary has authority to 

promulgate this rule, as the Secretary 

had for the other sections in 43 CFR part 

3160 and the onshore oil and gas orders. 

That authority includes the FLPMA, the 

MLA, the Mineral Leasing Act for 

Acquired Lands, and the various Indian 

mineral statutes. Each lease is expressly 

subject to existing and future 

regulations. The BLM has authority to 

condition or to deny APDs, and this rule 

extends that authority to proposals for 

hydraulic fracturing operations. 

Some commenters objected to the rule 

on the grounds that protection of water 

is a states’ rights issue. The BLM agrees 

to a certain extent, and has revised the 

rule, as discussed elsewhere, to reduce 

potential conflicts with states’ water 

allocation and water quality regulations. 

Other commenters said that the BLM 

lacks statutory authority to control 

water quality and usage because that 

authority is vested with the EPA and the 

states. 

The BLM is not controlling water 

quality or usage under this rule. 

Operators are responsible for complying 

with state or tribal requirements for 

obtaining water for use in hydraulic 

fracturing operations and for discharges 

into surface or groundwater. The BLM 

will not be issuing or vetoing rights to 

use water or discharge permits. 

However, the BLM will need to know an 

operator’s proposed source of water and 

planned disposal method in order to 

consider the potential environmental 

impacts and compliance with NEPA, 

but the BLM will not be adjudicating 

water rights. 

Federalism Assessment 

Some commenters believed that the 

rule requires a Federalism assessment 

under Executive Order (EO) 13132. The 

BLM believes that there will be no 

financial impacts to the states as a result 

of this rule. Operators will have some 

increases in costs, but the BLM does not 

believe that production from Federal 

lands will be reduced as a result of this 

rule. Therefore, a Federalism assessment 

is not required. 

Compliance With E.O. 12866 and E.O. 

13175 

Many commenters suggested that the 

annual costs of the rule would exceed 

$100 million per year and that the BLM 

failed to comply with E.O.12866 and 

E.O.13175. One commenter suggested 

that the costs would be $345 million per 

year, broken out as follows: $310 

million for enhanced casing costs; $5.6 

million for initial delay costs; $1.7 

million for administrative costs; $2.6 

million for cement logs; $5.9 million for 

log delays; and $19.6 million if the BLM 

were to require tanks to manage 

flowback. Other commenters referenced 

these cost figures. Another commenter 

suggested the costs of the rule could be 

as low as $30 million per year or as high 

as $2.7 billion per year. The range was 

due to uncertainty about the rule’s effect 

on field operations. The areas of 

uncertainty in the comments are related 

to drilling delays and completion 

schedules, the number of impacted 

wells, additional requirements resulting 

from the usable water definition, and 

costs to conduct CELs on surface and 

intermediate casing. Another 

commenter suggested a range of possible 

costs of $0–$750 million per year. 

The BLM has complied with 

E.O.12866 and E.O.13175. After 

reviewing and analyzing the submitted 

data, the BLM found that many of the 

assertions that the commenters made are 

based on flawed assumptions or 

confusion about the requirements in the 

rule. Commenters have also provided 

constructive feedback about rule 

provisions that would pose costs to 

operators that the BLM had not 

anticipated. Through the course of this 

rulemaking, the BLM adjusted 

requirements to better reflect the best 

management practices of operators 

conducting hydraulic fracturing 

operations and to resolve the 

unintended consequences that the 

proposed rules would have caused. The 

following discussion details comments 

by topic area. 

Commenters suggested that usable 

water is not fully defined, that there are 

costs associated with identifying usable 

water zones, and that the costs are 

variable and uncertain. Various 

commenters suggested per-well costs of 

$4,000–$5,000, $8,000–$10,000, 

$60,000, and $400,000. Activities 

associated with identifying usable water 

include drill logs, water sampling, 

geologic characterization ($3,000– 

$8,000 or up to $408,000 per field 

development), and drill stem testing 

($200,000 per test). 

As explained in the discussion of 

section 3162.3–3(d), the final rule 

removes the requirement that an 

operator must identify the usable water 

zones with a drill log. Existing Onshore 

Order 1 already requires that an 

operator’s drilling plan include the 

estimated depth and thickness of zones 

potentially containing usable water. In 

the final rule, the BLM expects 

operators to use all available 

information to identify usable water 

zones, consistent with Onshore Order 1. 

As such, and since this information will 

likely already be readily available to 

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operators, and is already required for 

the drilling plan, the BLM does not 

anticipate any incremental costs 

associated with identifying usable water 

zones. 

Commenters suggested that the BLM’s 

definition of usable water would pose 

additional costs, since the 10,000 ppm 

TDS standard in the proposed rule is 

higher than the 5,000 ppm TDS 

standard in the previous 43 CFR 

3162.5–2(d). Our detailed response to 

these comments appears in the 

discussion of the definition of usable 

water and in section 3162.3–3(d) of this 

preamble. In short, the current 

requirements regarding usable water 

exist in Onshore Order 2, which was 

published after the requirements in the 

previous section 3162.5–2(d). Onshore 

Order 2 specifies a 10,000 ppm TDS 

standard that is consistent with our 

definition in the proposed and final 

rules. While the previous section 

3162.5–2(d) specified a lower standard, 

it was superseded by Onshore Order 2 

in 1988. This final rule clarifies any 

confusion between the regulations in 

the CFR and Onshore Order 2 standards. 

Since the 10,000 ppm TDS standard is 

not new, it does not result in additional 

costs. 

Several commenters suggested that 

the rule would require operators to 

perform additional cementing that 

would pose costs to operators. A 

commenter’s analysis suggests that the 

rule would require operators to run 

deeper surface casing, two-stage 

cementing on the production casing, or 

the addition of an intermediate string of 

casing, for a total cost of $310M 

(calculated as 2,350 feet per well of 

additional casing at $37 per foot for 

3,566 wells). Another commenter 

suggested that, by requiring operators to 

run a CEL on all strings that protect 

usable water, operators would need to 

run cement for the entire lengths of 

these casings. 

As explained in the discussion of the 

definitions section and section 3162.3– 

3(d) of this preamble, because the 

definition of usable water has not 

substantially changed in this rule, and 

because existing Onshore Order 2 

already requires casing and cementing 

to protect and isolate all usable water 

zones, there will be no significant 

changes in costs of running casing and 

cement. 

Commenters generally believe that the 

economic analysis underestimates the 

costs of running CELs, particularly for 

CELs on the surface casing. One 

commenter’s analysis accepted the 

BLM’s cost estimates for the CEL 

requirement. Another commenter 

suggested the CEL costs would be 

$24,000–$109,000 per well ($3,500– 

$5,700 for a CBL log, or $5,000–$6,500 

for a CBL on the surface casing, $20,000 

for a CBL on the intermediate casing, 

and rig delay costs up to $100,000). One 

commenter suggested the BLM 

neglected to include $50,000 per day in 

rig time from the analysis. One 

commenter suggested using delay costs 

of $1,833.33/hour ($1,000 for rig costs 

and $833.33 for ancillary costs). 

Commenters referenced EPA guidance 

that cement should harden for 72 hours 

for each casing. 

As explained in the section 3162.3– 

3(c) discussion in this preamble, in the 

final rule the requirements for a CEL on 

the surface casing of a type well when 

cement returns to the surface with no 

indication of inadequate cementing are 

removed. The final rule instead requires 

well logging in a manner that is 

consistent with industry standards. The 

economic analysis is revised to account 

for this change. 

A commenter identified a formatting 

error in calculating the costs of a CEL 

on the intermediate casing. The 

commenter was correct, and the 

formatting error is corrected. 

Commenters suggested that MIT costs 

should be considered at a cost of 

$10,000 per test. The BLM disagrees that 

the costs of an MIT are attributable to 

the final rule. The requirements of the 

rule are consistent with industry 

guidance on hydraulic fracturing and 

with state regulations. Industry 

guidance states that the operator should 

pressure test the casing string through 

which the hydraulic fracturing will 

occur prior to commencing the 

hydraulic fracturing operation. API 

Guidance Document HF1 titled 

‘‘Hydraulic Fracturing Operations— 

Well Construction and Integrity 

Guidelines’’ (First Edition, October 

2009) states that ‘‘prior to perforating 

and hydraulic fracturing operations, the 

production casing should be pressure 

tested (commonly known as a casing 

pressure test). This test should be 

conducted at a pressure that will 

determine if the casing integrity is 

adequate to meet the well design and 

construction objectives’’ (p. 12). In 

addition, ‘‘prior to beginning the 

hydraulic fracture treatment, all 

equipment should be tested to make 

sure it is in good operating condition. 

All high-pressure lines leading from the 

pump trucks to the wellhead should be 

pressure tested to the maximum treating 

pressure’’ (p. 16). The BLM also 

reviewed state regulations in California, 

Colorado, Montana, New Mexico, North 

Dakota, Oklahoma, Texas, Utah, and 

Wyoming. From FY 2010 to FY 2013, 

the number of well completions on 

Federal and Indian lands in those states 

accounted for 99.3 percent of the total 

well completions on Federal and Indian 

lands nationwide. The state regulations 

in those states either require pressure 

tests on all casing strings or on the 

casing strings through which the 

completion operation will occur. 

Therefore, we believe that the MIT 

requirement will not pose an 

incremental cost to most responsible 

operators. 

Several commenters suggested that in 

order to provide the actual length and 

height of the fractures (see section 

3162.3–3(d)), an operator would have to 

conduct a ‘‘frack model’’ and that the 

associated costs are not accounted for in 

the analysis. They suggested that costs 

may range from $4,500–$200,000 per 

well depending on the sophistication of 

the modeling required. The BLM does 

not intend to require that operators 

undertake modeling. The BLM revised 

the requirement in section 3162.3–3(d) 

of the final rule to allow for greater 

operational flexibility, for example, by 

allowing operators to report the 

estimated length and height. Operators 

would not undertake the expense of 

hydraulically fracturing a well without 

an estimation or calculation of the 

propagation of the fissures. The final 

rule does not require additional 

modeling. 

In the supplemental proposed rule, 

the BLM solicited comments concerning 

the incremental costs of a requirement 

to manage flowback with tanks instead 

of lined pits. One commenter suggested 

lined impoundments or semi-rigid 

atmospheric tanks are more cost 

effective than steel tanks. It estimated 

the 5-year net present value costs at: 

Impoundments $2.3 million, semi-rigid 

tanks $2.42 million, steel tanks $23 

million). A commenter’s analysis 

suggested a tank requirement would 

cost $19.6 million per year (or $11,500 

per well). Another commenter suggested 

that an open pit costs $447,000 and a 

closed-loop system costs $267,000 (an 

$180,000 cost advantage). Section 

3162.3–3(h) of the final rule requires 

that operators manage recovered fluids 

in enclosed above-ground tanks until 

approval of a produced water plan 

pursuant to Onshore Order 7. The 

economic analysis has been revised to 

address the costs associated with this 

revision. 

One commenter suggested that 

hydraulic fracturing operations have 

additional ancillary costs that are borne 

by the public, including wider roads 

and more road maintenance. The 

economic analysis measures the 

incremental costs of implementing the 

rule, not all costs associated with 

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hydraulic fracturing. The BLM did not 

revise the rule or the analysis as a result 

of this comment. 

Several commenters suggested that 

the analysis should consider the cost of 

remedial cement squeezes. The practice 

of squeeze cementing is an operation in 

a well whereby a cement slurry is forced 

(squeezed) under pressure into a 

formation, or a channel behind the 

casing, or through holes purposely 

placed in the casing. One commenter 

suggested that costs for remedial cement 

squeezes may range between $0– 

$120,000, or $142,000 per well. Another 

commenter suggested that typical costs 

for cement remediation could include: 

Perforating casing—$12,000; squeeze 

cementing—$30,000; and post-squeeze 

CBLs—$6,000–$20,000. Further, the 

commenter believes that one cement 

squeeze would require 4 days and two 

squeezes would require 9 days to 

complete. The commenter estimated the 

minimum total cost to be $128,000 for 

a single cement squeeze and $284,000 

for two squeezes, considering rig delay 

time and direct remediation costs only. 

Further, the commenter suggests that 

there is uncertainty in how many 

cement remediation jobs would be 

required after the hydraulic fracturing 

operation occurs. 

The concerns about remedial cement 

squeezes were predicated on two 

arguments—that CELs are interpretive 

and that in implementing the rule, the 

BLM would require operators to perform 

remedial cement squeezes whenever the 

CEL detected a cement void. Final 

section 3162.3–3(e) does not require 

operators to run a CEL on the surface 

casing in every case. When there are 

indications of inadequate cement, the 

final rule specifies actions that an 

operator must take that are in line with 

current remedial procedures. Operators 

typically run CELs on the cement 

behind intermediate casings that protect 

usable water when they do not witness 

cement returns to surface. Therefore, the 

BLM believes that the CEL requirements 

in the final rule would not compel 

operators to take remedial action that 

they normally would not have taken 

otherwise. Thus, the revised 

requirements do not pose any 

incremental costs to operators. 

Commenters suggested that the type 

well concept is unclear and undefined. 

Commenters presented a range of 

estimates for type well applicability. A 

commenter suggested 3 percent to over 

50 percent per field depending on the 

maturity. A 5 percent increase in type 

well applicability is associated with a 

$34 million increase in industry costs. 

Another commenter suggests 14.29 

percent of all wells because 6–8 wells 

can be drilled from the same platform. 

Another commenter suggested it could 

mean one type well per section (10 type 

wells per 640-acre section). 

The final rule does not carry forward 

the type well concept or the CEL 

requirement for the surface casing. 

Thus, neither the costs of CELs for all 

surface casings, nor the cost savings 

from the type well are relevant for the 

final rule. 

Commenters suggested that the 

economic analysis should consider legal 

challenges and delays to APDs. The 

BLM did not revise the final rule or alter 

the analysis to consider potential legal 

challenges or APD delays, because any 

potential delays that might arise as a 

result of legal challenges are speculative 

and not the result of the rule itself. 

One commenter suggested that the 

analysis should account for the cost of 

labor required to implement the rule. In 

the economic analysis for both the 

initial proposed and the supplemental 

proposed rules, the BLM considered the 

additional BLM workload and cost 

required as a distributional cost. The 

BLM agrees with the comment and has 

revised the final analysis to include the 

labor costs as part of the total costs of 

the rule. 

Some commenters agreed with the 

BLM’s administrative cost estimate, 

while others thought that the estimate 

should be reevaluated. The 

administrative workload was based on 

the estimated agency review time. In the 

final rule’s analysis, the BLM 

reevaluated the administrative costs 

given the changes to the rule. The 

results of the BLM reevaluation are 

discussed later in the Paperwork 

Reduction Act section of this rule. 

Commenters suggested that the BLM 

failed to consider the effects on tribal 

governments, and that the rule will have 

a disproportionate effect on tribes. 

Commenters suggested that the 

compliance costs of the rule will 

discourage operators from developing 

resources on Federal and Indian lands, 

reduce royalties, and harm local 

economies. Some commenters suggest 

that there could be negative spillover 

effects on state and private lands as 

well. 

The analysis for the proposed and 

supplemental proposed rules included 

impacts on tribal lands. The BLM 

revised the final rule’s analysis to 

addresses these impacts. The BLM 

believes that the rule will not have a 

disproportionate effect on tribes, given 

the requirements are consistent with 

current industry best practices. 

Many commenters suggested that the 

economic analysis failed to quantify or 

describe the benefits of the rule and that 

the benefits must support the BLM’s 

proposed action. Commenters disagreed 

with the characterization of risk and of 

the incidence of problems. Commenters 

also acknowledged that the risk of 

hydraulic fracturing is largely unknown. 

One commenter suggests estimating the 

environmental risk or determining 

society’s willingness to pay for risk 

reduction. 

The BLM does not quantify the 

benefits of the rule, because it is unable 

to monetize the incremental reduction 

in risk that the rule confers. It further 

believes that determining society’s 

willingness to pay for risk reduction 

would need to rely on a firm 

understanding of the incremental risk 

reduction. However, this does not mean 

that the rule is without benefits. The 

final rule includes requirements, many 

of which are already consistent with 

industry guidance, to ensure that 

operators conduct hydraulic fracturing 

in a manner that minimizes 

environmental and health risks 

associated with these activities. These 

requirements are also generally 

consistent with several state regulations 

governing hydraulic fracturing. 

One commenter suggested that 

Federal Remediation Technologies 

Roundtable case studies referenced in 

the proposed rule’s economic analyses 

are inappropriate because none of the 

studies are studies of hydraulic 

fracturing operations. One commenter 

referenced testimony that the 

remediation of groundwater 

contaminated by oil and gas wastes can 

range from $100,000 to $1 million. The 

BLM included these figures in the 

analysis to provide context about the 

cost of potential problems, but it does 

not use the figures to quantify a benefit. 

Commenters suggested that the rule 

lacks economic justification and is 

unnecessary, that there have been no 

events of groundwater contamination, 

and the benefits must outweigh the 

costs. Elsewhere in this preamble we 

have discussed the need and purpose 

for the rule and it is prudent for the 

BLM to be proactive in the protection of 

resources on Federal and Indian lands. 

Throughout the rulemaking process, the 

BLM has been mindful of the potential 

compliance costs to the operator. The 

requirements in the final rule are 

consistent with industry best practices 

and the burden should be minimal. In 

addition to that, the rule is necessary 

given the overall scale of development 

and emergence of increasingly complex 

hydraulic fracturing operations that 

apply increased pressures and volumes 

of fluid within the subsurface. The BLM 

agrees that efforts to trace contaminants 

in groundwater to specific hydraulic 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16189 

10CEQ, Forty Most Asked Questions Concerning 

CEQ’s National Environmental Policy Act 

Regulations, 46 FR 18026, 18027 (1981) (Q 2a–). 

fracturing operations have been 

controversial, in light of the technical 

difficulties and scientific uncertainties. 

But no law requires the BLM to wait for 

a significant pollution event before 

promulgating common-sense 

preventative regulations. Also, the 

numerous official reports of frack hits 

(unplanned surges of pressurized fluid 

from hydraulic fracturing operations 

into other wells) show that the industry 

is in need of regulation to protect other 

wells and to prevent contamination of 

surface and possibly sub-surface 

resources caused by frack hits. 

Commenters suggested that some of 

the requirements in the rule are 

duplicative of state rules, that the rule 

is duplicative and unnecessary, and that 

the analysis should reflect that. The 

economic analysis accounts for areas in 

which the rule’s requirements are 

consistent with existing requirements 

(whether in current BLM onshore orders 

or in state regulations) or consistent 

with current industry best practice. For 

activities required by the rule that are 

already performed by operators, the 

economic analysis does not attribute the 

costs of those activities to the final rule. 

Commenters suggested that wells that 

have been constructed prior to this rule 

should be grandfathered. Otherwise, 

operators would have to workover wells 

to comply with cement repair 

provisions. If not, those costs should be 

considered. As described in the 

discussion of final section 3162.3–3(a), 

the final rule clarifies which paragraphs 

of the final rule will apply to wells 

constructed prior to the effective date of 

the rule, and the economic analysis 

reflects the terms of the final rule. 

Operators planning to conduct 

hydraulic fracturing on existing wells 

will need to submit documentation that 

demonstrates that adequate cementing 

was achieved for all casing strings 

designed to isolate and protect usable 

water. Monitoring reports of cement jobs 

are common in the industry and the 

operator should be able to provide such 

documentation to the BLM without any 

burden even for wells drilled prior to 

this rule. For older completed wells, to 

the extent that these reports are not 

available, the operator may provide any 

other information or perform any other 

measures deemed necessary by the 

authorized officer to assure that the 

cementing will isolate and protect 

usable water zones. Operators planning 

to conduct hydraulic fracturing on 

existing wells will also need to 

demonstrate that there is at least 200 

feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. Operators will be able to run a 

CEL on the production casing, as is 

consistent with prudent operating 

practice, without an additional cost 

burden. 

Environmental Impacts 

Certain commenters expressed 

concern stating that the environmental 

assessment (EA) did not consider a 

reasonable range of alternatives to the 

proposed action. Commenters claimed 

that, other than the No Action 

alternative, all alternatives looked too 

similar to be considered different 

alternatives. Commenters further 

suggested that the BLM consider 

alternatives that: (1) Do not impose 

cement evaluation log (CEL) 

requirements; (2) Defer to states with 

hydraulic fracturing rules regardless of 

whether they meet or exceed the 

requirements of the BLM’s rule; (3) Ban 

hydraulic fracturing entirely or in 

sensitive areas; (4) Regulate air 

emissions from hydraulic fracturing 

operations; (5) Ban the use of diesel in 

hydraulic fracturing fluid; or (6) Ban the 

use of harmful chemicals in hydraulic 

fracturing fluid. 

To help inform the development of 

the hydraulic fracturing rule, the 

Secretary and the BLM hosted forums in 

Washington, DC and various parts of the 

country to receive input from the public 

regarding their concerns about 

hydraulic fracturing activities on 

onshore Federal and Indian lands. A 

majority of the concerns raised during 

the sessions relate to the risks hydraulic 

fracturing activities pose to surface and 

subsurface sources of water, the 

constituents of the fluids injected into 

the ground as part of the hydraulic 

fracturing process, and concerns over 

the management of the fluids used 

during and recovered after a well is 

fractured. 

The information gathered from these 

sessions, coupled with the BLM’s 

authority to regulate all oil and gas 

operations on Federal and Indian lands, 

helped guide the development of the 

BLM’s Purpose and Need statement in 

the environmental assessment (EA). 

The Purpose and Need section of the 

EA states that ‘‘The BLM’s existing 

limited regulations pertaining to 

hydraulic fracturing operations need 

strengthening to provide adequate 

protection of water resources.’’ The 

Purpose and Need section of the EA 

further states that, ‘‘Pursuant to the 

FLPMA, the Indian mineral leasing acts, 

and other statutes, the BLM administers 

oil and gas operations in a manner that 

protects Federal and Indian lands, while 

providing for opportunities to develop 

oil and gas resources on those lands.’’ 

The BLM’s obligation under NEPA is 

to analyze a reasonable range of 

alternatives (not every conceivable 

alternative) that would meet the 

bureau’s purpose and need for Federal 

action and allow for a reasoned choice 

among alternatives to be made. The 

Council on Environmental Quality 

(CEQ) has determined that ‘‘Reasonable 

alternatives include those that are 

practical or feasible from the technical 

and economic standpoint and using 

common sense, rather than simply 

desirable from the standpoint of the 

applicant.’’ 10

The BLM analyzed six alternatives 

that respond to the BLM’s purpose and 

need for Federal action. These 

alternatives consider a broad range of 

prescriptions for how hydraulic 

fracturing operations should be 

regulated, including the option of not 

promulgating a rule—the No Action 

alternative. Regarding the action 

alternatives, Alternative B seeks to 

regulate all forms of well stimulation, 

including hydraulic fracturing, and 

prescribes a particular way to confirm 

wellbore integrity and zonal isolation of 

usable water-bearing zones, i.e., through 

the use of cement bond logs for all wells 

that are to be stimulated. In contrast, 

Alternative E seeks to regulate hydraulic 

fracturing operations specifically, and 

broadens the set of cement evaluation 

tools that may be used (not just a 

cement bond log) to confirm wellbore 

integrity and zonal isolation of usable 

water-bearing zones. Alternative E also 

evaluates the concept of a type well, 

which would serve as a model well for 

hydraulic fracturing in a field where 

geologic characteristics are similar. A 

cement evaluation log would not be 

required for all wells that would 

replicate the successful type well in the 

same field. The BLM also looked at 

alternatives that were less and more 

restrictive in the way recovered fluids 

should be handled. The following table 

outlines the alternatives that the BLM 

considered as part of its NEPA analysis. 

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16190 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

Name of alternative Description of alternative 

Alternative A—No Action .......................................................................... Under this alternative, the BLM would neither promulgate a rule to 

amend existing regulations nor add any new regulation. 

Alternative B—Initial Proposed Well Stimulation Rule ............................. Under this alternative, the BLM would promulgate the well stimulation 

rule entitled Oil and Gas; Well Stimulation, Including Hydraulic Fracturing, on Federal and Indian Lands, which was published in the 

Federal Register on May 11, 2012 (77 FR 27691) 

Alternative C—Unlined Pits ...................................................................... This alternative is identical to Alternative A except oil and gas operators would not be required to line the pits that store the fluids flowed 

back from a well after well stimulation operations are complete. 

Alternative D—Storage Tank Requirement .............................................. This alternative is identical to Alternative B except that it requires oil 

and gas operators to use storage tanks to manage flowback. 

Alternative E—Proposed Action—Supplemental Proposed Hydraulic 

Fracturing Rule.

Under this alternative, the BLM would promulgate the supplemental 

proposed hydraulic fracturing rule entitled Oil and Gas; Hydraulic 

Fracturing on Federal and Indian Lands, which was published in the 

Federal Register on May 24, 2013 (78 FR 31636). This alternative 

is similar to Alternative B, the Initial Proposed Rule, except it contains sufficient changes that publication of a revised proposed rule 

was necessary. 

Alternative F—BLM Preferred Alternative, Final Hydraulic Fracturing 

Rule.

Under this alternative, the BLM would promulgate the final rule entitled: 

Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands. This 

alternative is similar to Alternative E, but with certain modifications 

based on comments received during the public comment period for 

the Supplemental Proposed Rule on Oil and Gas; Hydraulic Fracturing, on Federal and Indian Lands. 

Alternative C evaluated the option of 

not requiring operators to line their pits 

to temporarily store recovered fluids. 

Alternative D evaluated the option of 

requiring operators to use only storage 

tanks to store recovered fluids. Under 

Alternative F, the BLM requires the use 

of rigid enclosed, covered, or netted and 

screened above-ground tanks with a 500 

bbl capacity, but will consider the use 

of a lined pit so long as the risk of 

adversely affecting sensitive water 

resources, such as surface water and 

shallow groundwater, was low and use 

of storage tanks was infeasible for 

environmental, public health, or safety 

reasons. However, Alternative F does 

not include a requirement to perform a 

cement evaluation log on all casing 

strings. Rather, it requires operators to 

circulate cement to the surface for the 

surface casing and either circulate 

cement to the surface or run a CEL on 

the intermediate and production casing, 

in addition to performing specific well 

integrity tests, to confirm wellbore 

integrity and zonal isolation. These 

alternatives meet the BLM’s purpose 

and need for Federal action and comply 

with CEQ’s requirement to also consider 

the No Action alternative, which is 

Alternative A. 

In addition to the six alternatives 

analyzed in the environmental 

assessment, the BLM also considered 

additional alternatives that were 

eliminated from detailed analysis. The 

BLM considered an alternative to defer 

to the states’ and tribes’ hydraulic 

fracturing rules regardless of whether 

those rules meet or exceed the agency’s 

hydraulic fracturing requirement. 

However, those governments are 

regulating hydraulic fracturing 

operations in varying ways. For 

example, the state regulations range 

from not regulating the activity at all in 

some states to fairly comprehensive 

regulation in other states. The BLM 

administers oil and gas operations in 

many states and on various Indian 

reservations, and the agency needs a 

baseline set of standards that would 

apply to Federal and Indian oil and gas 

leases in all states. These standards 

must meet the agency’s unique 

responsibilities under the FLPMA, the 

Indian mineral leasing acts, and other 

statutes to administer oil and gas 

operations in a manner that protects 

Federal and Indian lands. The BLM’s 

regulations are necessary because the 

BLM is unable to delegate its 

responsibilities to the states and tribes. 

An alternative that would defer to state 

and tribal hydraulic fracturing rules, 

even in circumstances where those rules 

do not meet or exceed the requirements 

of the BLM’s rule, would not meet the 

purpose and need for the BLM’s action. 

Moreover, an alternative deferring only 

to more stringent regulations would be 

unnecessary. None of the alternatives 

considered by the BLM for this 

rulemaking would preempt a more 

stringent state or tribal law. Unless a 

specific variance is granted by the BLM, 

operators on Federal leases must 

comply both with this rule and any 

applicable state requirements, just as 

they already must comply with both 

BLM rules and state rules on a variety 

of drilling and completion issues. This 

alternative was therefore not carried 

forward for further analysis. 

The BLM considered an alternative 

that would ban hydraulic fracturing 

activities in all areas. However, such an 

alternative may render most oil and gas 

development projects on Federal and 

Indian land infeasible, as indicated by 

the fact that the BLM estimates that 90 

percent of the wells drilled on Federal 

and Indian land are hydraulically 

fractured. The BLM has a responsibility 

under the FLPMA to act as a steward for 

the development, conservation, and 

protection of Federal lands, by 

implementing multiple use principles 

and recognizing, among other values, 

the Nation’s need for domestic sources 

of minerals from the public lands. The 

Secretary of the Interior has 

responsibilities under the Indian 

mineral leasing acts to assist tribes and 

individual Indians in obtaining the 

benefits of mineral development while 

protecting other resources. A ban or 

moratorium would not satisfy the BLM’s 

development responsibility under the 

FLPMA, or the Secretary’s 

responsibilities under other statutes, 

when regulations can adequately reduce 

the risks associated with hydraulic 

fracturing operations. In addition, a part 

of the BLM’s purpose and need for this 

action is to administer oil and gas 

operations in a manner that protects 

Federal and Indian lands while 

providing for opportunities to develop 

oil and gas resources on those lands. An 

alternative that would ban or place a 

moratorium on hydraulic fracturing 

operations would not meet the purpose 

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and need for the BLM’s action, and was 

not carried forward for further analysis. 

Similarly, the BLM considered an 

alternative that would ban hydraulic 

fracturing activities in sensitive areas. 

However, the BLM has other tools and 

processes in place to ensure protection 

of sensitive areas. For example, the BLM 

has rules at 43 CFR 3100.0–3(a)(2)(iii) 

that prohibit the leasing of Federal 

minerals beneath incorporated cities, 

towns, and villages. Also, during 

development of a Resource Management 

Plan (RMP), the BLM identifies areas 

needing protection as areas closed to 

leasing or areas open to leasing, but 

with stipulations that limit or prohibit 

surface occupancy. Further, specific 

setbacks from sensitive areas are more 

effective when they are determined at a 

level where the information associated 

with a given sensitive area is available. 

That information is gathered and 

maintained at the field office level 

where specific drilling and hydraulic 

fracturing operations are permitted. At 

the permitting stage, the BLM conducts 

additional analysis as required by 

NEPA, when drilling/hydraulic 

fracturing proposals are received. The 

analysis includes onsite inspections, 

which identify any additional sensitive 

areas. Using that information, the BLM 

then develops proper mitigation to 

protect these areas. Mitigation could 

include moving the well location or 

including site-specific conditions of 

approval (COAs). In addition, if 

unnecessary or undue degradation 

impacts are identified on public land, or 

unacceptable impacts are identified on 

Indian land, which cannot be mitigated, 

the BLM may deny the proposal. 

Through existing regulations, the RMP 

process, and the subsequent site-specific 

analyses, the BLM has or can specify 

measures to ensure protection of 

sensitive areas. Furthermore, state setback requirements would normally 

apply on Federal lands, and tribal setback requirements would apply on 

tribal lands (see also existing section 

3162.3–1(b)). Since setback 

requirements are already addressed in 

existing regulations, land use planning, 

and internal processes and policy, 

minimum setback distances are not 

necessary in this rule. For these reasons, 

an alternative that entails setbacks from 

sensitive areas would not be a 

reasonable alternative, and was not 

carried forward for further analysis. 

The BLM considered an alternative 

that would regulate emissions 

associated with the hydraulic fracturing 

process. However, this alternative is not 

within the scope of this rulemaking. The 

purpose and need for the BLM’s action 

is, among other things, to improve its 

regulatory framework to account for 

hydraulic fracturing activities and 

establish procedures that would provide 

adequate protection of water resources 

on Federal and Indian lands. Please note 

that the EPA issued final rules to reduce 

air pollution from the oil and natural 

gas industry. The final rules were issued 

in 2012 and include air standards for 

natural gas wells that are hydraulically 

fractured. For these reasons, the 

alternative was not carried forward for 

analysis. 

The BLM considered an alternative 

that would ban the use of harmful 

chemicals in the fluids used to 

hydraulically fracture a well. Chemicals 

used during the hydraulic fracturing 

process are tailored to the downhole 

conditions of a given well. In this rule, 

to be conservative, the BLM treats all 

chemicals used in hydraulic fracturing 

as if they were hazardous. Thus, the rule 

is written to ensure that all hydraulic 

fracturing fluids are confined to the 

intended zone and do not contaminate 

usable water zones, and that recovered 

fluids do not contaminate surface or 

groundwater. For these reasons, an 

alternative to ban hazardous chemicals 

was not carried forward for analysis. 

Similarly, the BLM considered an 

alternative that bans the use of diesel 

fuel in hydraulic fracturing fluids. 

Diesel fuel is used as a base fluid 

instead of water where the hydrocarbonbearing formation would swell when 

coming into contact with water, limiting 

or preventing the flow of oil and gas 

into the wellbore. The regulation of 

diesel fuel in hydraulic fracturing fluids 

is committed to EPA under the SDWA 

and the Energy Policy Act of 2005. The 

action alternatives would prevent 

hydraulic fracturing fluids, recovered 

fluids, and hydrocarbons from 

contaminating usable water sources. 

Banning the use of diesel fuel on 

Federal and Indian lands could prevent 

some oil and gas resources from being 

developed, even though such operations 

would be allowed by the EPA’s 

regulations and guidance. That would 

not serve the purpose and need for the 

regulation. Accordingly, an alternative 

to ban the use of diesel fuel was not 

carried forward for analysis. 

Certain commenters recommended 

that the BLM not only analyze the 

impacts from the proposed rule, but 

rather all impacts associated with 

hydraulic fracturing operations in order 

to determine the effectiveness of the 

rule. Those commenters wanted an 

analysis of impacts to landscapes, air, 

wildlife, etc., as well as increased 

greenhouse gas emissions released as a 

result of increased production from 

unconventional sources made available 

only because of hydraulic fracturing 

technologies. 

An expanded description of hydraulic 

fracturing operations is provided in the 

Environmental Impacts section of the 

EA, and in the discussion of the No 

Action Alternative. Analyzing impacts 

associated with actual site-specific 

hydraulic fracturing activities is outside 

the scope of the EA for this rule. The 

BLM’s Preferred Alternative is not to 

consider the approval of a specific 

hydraulic fracturing operation, but 

rather to consider how its existing rules 

should be revised to respond to changes 

in technologies for hydraulic fracturing 

and the public’s concern regarding the 

practice. Approvals to develop Federal 

and Indian oil and gas resources 

(including proposals to hydraulically 

fracture wells) are made at different 

levels of the agency’s organization and 

during various decision-making 

processes—land use planning, oil and 

gas leasing, and permitting. It is at those 

decision points where the BLM would 

analyze, through the NEPA process, 

impacts to landscapes, air, wildlife, etc., 

as well as greenhouse gas emissions 

released from oil and gas development. 

The BLM has analyzed the action 

alternatives in comparison to the No 

Action Alternative. The CEQ requires 

that a No Action Alternative be 

considered. The No Action Alternative 

would not amend the BLM’s oil and gas 

regulations. Instead oil and gas activities 

on Federal and Indian lands would 

continue under existing regulations. The 

No Action Alternative provides a useful 

basis for comparison, enabling decisionmakers to compare the magnitude of 

environmental effects of the action 

alternatives against the No Action 

Alternative. The No Action alternative 

also demonstrates the consequences of 

not meeting the need for the action. 

The BLM has evaluated the 

effectiveness of the rule when 

evaluating the effects of the No Action 

Alternative in Chapter IV of the EA. The 

BLM determined that if none of the 

action alternatives were to be 

implemented, operators or their 

contractors would still perform 

hydraulic fracturing operations on 

Federal and Indian lands, usually 

without the BLM’s prior approval, and 

without performance standards specific 

for wells to be fractured. The BLM and 

the public would not have an adequate 

assurance that hydraulic fracturing 

operations performed on Federal and 

Indian lands are conducted in a safe and 

environmentally sound manner, 

particularly because there would not be 

a regulation that provides: (1) For the 

disclosure of chemicals used in the 

stimulation process; (2) A means to 

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confirm that all hydraulically fractured 

wells would be able to withstand the 

pressures of an anticipated hydraulic 

fracturing event and that all chemicals 

injected would be contained within the 

well and targeted producing formations; 

or (3) An assurance that the fluids 

recovered from the hydraulic fracturing 

process are handled and disposed of 

properly. 

Some commenters believe that the 

scope of the rule requires the 

preparation of an EIS. The comments in 

favor of an EIS make one or more of 

three different positions. First, some 

commenters believe that an EIS is 

required because of the trade secrets 

provision within the rule. Although the 

rule contains requirements for 

disclosure, there are provisions that 

allow operators to withhold trade 

secrets. Those commenters said that the 

BLM cannot claim that the rule’s 

chemical disclosure requirement will 

help the agency and other agencies 

make an accurate determination of 

whether hydraulically fractured fluids 

could be the source of any future reports 

of groundwater contamination. Without 

the information about trade secrets, the 

commenters said, future approvals of 

hydraulic fracturing operations could 

not accurately predict environmental 

impacts, and thus the BLM should 

prepare an EIS for the final rule. 

Second, some commenters believe 

that an EIS is required because multiple 

significance factors are present under 

the regulations which would govern 

widespread hydraulic fracturing on 

public lands throughout the country. 

The alleged significance factors include 

adverse environmental effects, 

significant impacts to public health and 

safety, unique characteristics of the 

geographic area, controversial effects, 

uncertain risks, cumulatively significant 

impacts, adverse effects to threatened 

and endangered species, and potential 

violations of environmental laws. 

Commenters said that the significant 

impacts of widespread hydraulic 

fracturing on public lands that would 

take place under the regulations 

contradict BLM’s ultimate conclusion in 

the EA that the proposed regulations 

would have no significant impacts on 

the environment. 

Third, some commenters have 

expressed concern with the EA’s 

analysis of socioeconomic impacts. 

Commenters said a nationwide rule that 

has economic and employment impacts 

is a major Federal action requiring the 

preparation of an EIS, therefore, the 

NEPA analysis performed for the 

proposed rule is inadequate. The 

commenter said that the BLM is in error 

in determining that an EA is sufficient 

to analyze the impacts associated with 

the rule. The commenter said that a 

nationwide rule of this magnitude and 

its coinciding economic and 

employment impacts certainly rise to 

the level of ‘‘Major Federal Action,’’ and 

therefore questioned the BLM’s 

determination that an EA is sufficient. 

The BLM has not prepared an EIS in 

response to those comments. First, the 

comments based on the trade secrets 

provisions miss the point that BLM’s 

evaluation of the impacts associated 

with promulgation of the rule, and with 

the BLM’s later evaluation of site 

specific impacts, does not require 

operators to disclose trade secrets. The 

BLM will make its decisions on 

proposals to conduct hydraulic 

fracturing operations on the assumption 

that the operations will use hazardous 

chemicals. The BLM will not approve 

proposals unless the operator 

demonstrates that the well was cased, 

cemented, and tested to show that it 

will isolate and protect usable water, 

and that recovered fluids will be 

isolated from surface and groundwater. 

The precise chemical constituents are 

not necessary for the BLM to assure that 

the operation will protect surface and 

groundwater. Exemptions from public 

disclosure for trade secrets or 

confidential business information will 

not prevent the BLM from assessing the 

environmental impacts of future 

hydraulic fracturing operations, and 

thus do not require an EIS for this rule. 

Second, the comments that advocate 

an EIS because of multiple significance 

factors which would govern widespread 

hydraulic fracturing on public lands 

throughout the country misunderstand 

the effect and impact of this rule. 

Federal agencies are required to prepare 

an EIS when they will take a major 

Federal action that will potentially have 

a significant effect (direct, indirect, or 

cumulatively) on the human 

environment. The BLM’s action is to 

update its existing regulations that 

pertain to hydraulic fracturing 

operations on Federal and Indian leases. 

Analyzing impacts associated with 

actual site-specific hydraulic fracturing 

activities is outside the scope of the EA 

for this rule. The BLM’s proposed action 

is not to consider the approval of a 

specific hydraulic fracturing operation, 

but rather to consider how its existing 

rules should be revised to respond to 

changes in technologies for hydraulic 

fracturing and the public’s concern 

regarding the practice. Approvals to 

develop Federal and Indian oil and gas 

resources (including proposals to 

hydraulically fracture wells) are made at 

different levels of the agency’s 

organization and during various 

decision-making processes—land use 

planning, oil and gas leasing, and 

permitting. It is at those decision points 

where the BLM would conduct further 

analysis under NEPA to evaluate 

impacts to landscapes, air, wildlife, etc., 

as well as increased greenhouse gas 

emissions released from oil and gas 

development. 

In the EA prepared for this rule, the 

BLM evaluated a range of reasonable 

alternatives, including the final rule, to 

determine whether its promulgation of 

the final rule would result in a 

significant effect on the human 

environment. In making its Finding of 

No Significant Impact (FONSI), the BLM 

considered the significance factors set 

out in 40 CFR 1508.27, which include 

the significance factors identified by 

commenters. For the reasons discussed 

in more detail in the EA and FONSI, the 

BLM concluded that the final rule 

would not have a significant impact on 

the environment and that no EIS was 

required. 

Furthermore, the rule is not 

connected to other actions that may 

require an EIS because it does not 

automatically trigger land use planning 

decisions, oil and gas leasing, or 

hydraulic fracturing operations. The 

rule will be in effect regardless of any 

previous leasing or development. The 

rule is not an interdependent part of a 

larger action and it does not depend on 

any larger action for its justification. 

The rule will govern future hydraulic 

fracturing operations, as will 

stipulations in oil and gas leases, and 

COAs in permits to drill. The lease 

stipulations and COAs can address local 

conditions and resources. Thus, the rule 

does not foreclose reasonable mitigation 

for site-specific direct, indirect, or 

cumulative impacts. 

Under the CEQ’s regulations, an EIS is 

required only if the issuance of a rule 

or regulation may significantly affect the 

quality of the human environment. 40 

CFR 1508.18. The human environment 

includes the natural and physical 

environment and the relationship of 

people with that environment, but 

economic or social effects do not by 

themselves require preparation of an 

EIS. 40 CFR 1508.14. The EA refers to 

and analyzes the socioeconomic impacts 

of the rule that are provided in the 

separate economic analysis. The 

economic analysis shows that the rule 

will increase compliance costs of 

operators, but also discloses that those 

increased costs would be only a small 

percentage of the costs of drilling and 

hydraulically fracturing an oil and gas 

well. Thus, only marginally prospective 

lands could even theoretically become 

less attractive to the oil industry, and 

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the employment and revenue impacts of 

the rule, if any, will be impossible to 

separate from the greater influences of 

geologic conditions, technological 

innovations, and market forces. The 

BLM’s EA thus appropriately 

determined that there would be no 

significant impacts to the quality of the 

human environment, and it is not 

necessary for the BLM to prepare an EIS. 

Certain commenters stated that the 

BLM did not inform the public that it 

was preparing a NEPA analysis, nor did 

it circulate a draft EA. Other 

commenters expressed similar concern 

saying the BLM did not provide a public 

comment period and therefore, the 

public was not able to provide 

meaningful input at a time when the 

environmental analysis could have been 

altered and improved. 

Unlike the procedures for issuing an 

EIS, which includes specific formal 

notification requirements through the 

Federal Register and minimum 

requirements for inviting public 

comments, the CEQ’s and the DOI’s 

NEPA implementing regulations require 

Federal agencies to involve the public 

when preparing an EA, but gives 

discretion to each agency to determine 

whether it is appropriate to make the EA 

available for public comment and 

review. 

On May 11, 2012, the BLM issued the 

notice of proposed rulemaking and then 

issued a supplemental notice of 

proposed rulemaking on May 24, 2013. 

The 2012 proposal was available for 

public comment for 120 days and the 

2013 notice was available for 90 days. 

Both rules put the public on notice that 

the EA was available for review and 

comment along with the other 

documents in the administrative record. 

The BLM, in fact, received several 

comments concerning the substance of 

the EA, and those comments have been 

considered. Thus, comments suggesting 

that the EA was unavailable, or not 

properly made available for comment, 

are incorrect. 

III. Procedural Matters 

Federal and Indian Oil and Gas Leasing 

Activity 

To understand the context of the costs 

and benefits of this rule, the BLM 

includes background information 

concerning the BLM’s leasing of Federal 

oil and gas, and management of Federal 

and Indian leases. This analysis 

explains the basis for the conclusions 

related to the procedural matters 

sections that follow. The BLM Oil and 

Gas Management program is one of the 

largest mineral leasing programs in the 

Federal Government. At the end of fiscal 

year (FY) 2013, there were 47,427 

Federal oil and gas leases covering 

36,092,482 acres, 93,598 producible and 

service drill holes, and 99,975 

producible and service completions on 

Federal leases. Table 1 shows the sales 

volume, sales value, and royalty 

generated from Federal and Indian oil 

and gas production in 2013. For FY 

2013, onshore Federal oil and gas leases 

produced about 133 million bbl of oil, 

2.67 trillion cubic feet (Tcf) of natural 

gas, and 2.5 billion gallons (Gal) of 

natural gas liquids, with a sales value of 

almost $24 billion and generating 

royalties of almost $2.7 billion. Oil and 

gas production from Indian leases was 

almost 46 million bbl of oil, 238 billion 

cubic feet (Bcf) of natural gas, and 155 

million gallons of natural gas liquids, 

with a sales value of over $5 billion and 

generating royalties of $860 million for 

the Indian mineral owners. 

TABLE 1—FEDERAL AND INDIAN OIL AND GAS PRODUCTION AND ROYALTIES, FISCAL YEAR 2013 

Jurisdiction Commodity Sales volume Sales value Revenue 

Federal Leases ...................................... Oil (bbl) .................................................. 133,364,128 $11,927,069,991 $1,444,886,822 

Gas (Mcf) .............................................. 2,662,577,254 9,905,897,816 1,051,198,875 

NGL (Gal) .............................................. 2,477,721,602 2,076,639,138 195,789,932 

Subtotal ........................................... ................................................................ .............................. 23,909,606,945 2,691,875,629 

Indian Leases ......................................... Oil (bbl) .................................................. 45,966,597 4,137,453,205 721,089,106 

Gas (Mcf) .............................................. 238,717,918 813,440,706 124,217,560 

NGL (Gal) .............................................. 155,399,916 135,369,266 15,192,781 

Subtotal ........................................... ................................................................ .............................. 5,086,263,176 860,499,447 

Source: Office of Natural Resources Revenue (ONRR), Federal Onshore Reported Royalty Revenue, FY 2013 and American Indian Reported 

Royalty Revenue, FY 2013. 

Need for Policy Action 

To summarize the need for policy 

action, the National Academy of Science 

has identified three potential pathways 

for hydraulic fracturing fluids or oil and 

gas from hydraulic fracturing operations 

to contaminate usable water resources. 

The BLM agrees that the most likely 

pathway would be a leak in the wellbore 

casing, and that assurances of the 

strength of the casing are appropriate. 

The BLM also believes that it is 

important to consider known faults or 

natural fissures that could serve as 

pathways between the fractured zone 

and usable water before approving a 

hydraulic fracturing operation. A related 

issue is prevention of ‘‘frack hits,’’ 

which are unplanned surges of 

pressurized fluids from one wellbore 

into another wellbore. Frack hits have 

resulted in surface spills on Federal and 

non-federal lands and have caused the 

loss of recoverable oil and gas, but they 

have not yet been shown to be a source 

of contamination of usable water. 

Furthermore, proper management of 

recovered fluids on the surface is 

necessary to prevent leaks and spills 

that could contaminate surface waters 

and shallow aquifers; the BLM needs to 

fill the existing regulatory gap between 

completion of a hydraulic fracturing 

operation and the implementation of an 

approved plan for permanent disposal 

of produced water. Finally, the BLM, 

the public, and tribes should have 

access to information about the 

chemicals injected into Federal or 

Indian lands, consistent with statutory 

protections for proprietary information. 

The following discusses those needs for 

policy action in more detail. 

Much of the debate about hydraulic 

fracturing has centered on fluid or gas 

migration; that is, the potential that 

hydraulic fracturing fluids pumped into 

deep geologic formations, or oil or gas 

liberated by hydraulic fracturing will 

migrate into shallower drinking water 

sources with potential contamination 

made more likely if the wellbore 

integrity is compromised. Most reports 

suggesting that hydraulic fracturing 

operations contributed to contamination 

of water supplies involve instances of 

abnormally high concentrations of 

methane in water wells or monitoring 

wells in or near areas with active oil and 

gas drilling. 

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16194 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

11Osborn, S., et al. (2011). Methane 

contamination of drinking water accompanying gaswell drilling and hydraulic fracturing. Proceedings 

of the National Academy of Sciences. 

12Warner, N., et al. (2012). Geochemical evidence 

for possible natural migration of Marcellus 

Formation brine to shallow aquifers in 

Pennsylvania. Proceedings of the National Academy 

of Sciences, Vol. 109, July 24, 2012. 

13U.S. Environmental Protection Agency (May 

20, 2014). Natural Gas Extraction—Hydraulic 

Fracturing: Providing Regulatory Clarity and 

Protections against Known Risks. Retrieved from 

http://www2.epa.gov/hydraulicfracturing#

providing. 

14Secretary of Energy Advisory Board (2011). 

Shale Gas Production Subcommittee Second Ninety 

Day Report. November 18, 2011. Retrieved from 

http://www.shalegas.energy.gov/resources/111811_

final_report.pdf. 

For example, the National Academy 

of Sciences issued reports in 2011 11 and 

in 2012 12 finding that there are at least 

three possible mechanisms for fluid 

migration into shallow drinking-water 

aquifers that could help explain the 

increased methane concentrations 

observed in water wells that existed 

around shale gas wells in Pennsylvania: 

1. The movement of gas-rich solutions 

within the shale formations up into 

shallow drinking-water aquifers; 

2. The movement of gas through 

inadequately constructed, or leaky gaswell casings; and 

3. The creation of new or enlarging of 

existing fractures above the shale 

formation as a result of hydraulic 

fracturing, which increases the 

connectivity of the entire fracture 

system, thus allowing the gas to absolve 

out of solution and migrate through the 

fracture systems and into shallow 

aquifers. 

These reports have indicated that the 

movement of gas-rich solutions within 

the shale formations up into shallow 

drinking-water aquifers is the least 

likely possibility. This is due primarily 

to the extensive distance between the 

shale formations and the shallow 

aquifers as well as high underground 

pressures exerted against the deep shale 

formations. The most likely possibility 

for gas contamination would be from 

leaky gas-well casings. These leaks 

could occur at hundreds of feet 

underground, with methane passing 

laterally through the well casing and 

vertically through fracture systems. 

There is also a possibility for gases to 

migrate through fractures above the 

shale formation that is created or 

enlarged as a result of hydraulic 

fracturing and thus expanding the 

overall underground fracture system. 

These new fractures could potentially 

relieve the pressures exerted against 

these gas-rich solutions, which would 

allow the gas to come out of solution 

and migrate through the fracture system 

and potentially into shallow aquifers or 

improperly plugged wells. However, 

these researchers have stated that the 

possibility of such occurrence is 

unlikely, but still unknown. 

The focus on fluid or gas migration is 

only one aspect of potential damage. 

According to the EPA, there are other 

potential impacts, including stress on 

surface water and groundwater supplies 

from the withdrawal of large volumes of 

water used in drilling and hydraulic 

fracturing, contamination of 

underground sources of drinking water 

and surface waters resulting from spills, 

faulty well construction, or by other 

means, and adverse impacts from 

discharges into surface waters or from 

disposal into underground injection 

wells.13

The BLM is aware that a small 

number of hydraulic fracturing 

operations on Federal lands have 

communicated with other wells in their 

vicinity. Those hydraulic fracturing 

operations created fractures that 

connected with existing fissures or 

fractures in the shale, allowing 

pressurized fluids to flow into nearby 

wellbores. During these instances of 

downhole inter-well communication, 

known as ‘‘frack hits,’’ the pumped-in 

hydraulic fracturing fluid may flow into 

and up through a nearby well, causing 

a blow out and spill. 

The Secretary of Energy’s Advisory 

Board 

At the President’s direction, the 

Secretary of Energy’s Advisory Board 

convened a Natural Gas Subcommittee 

to evaluate hydraulic fracturing issues. 

The subcommittee met with industry, 

service providers, state and Federal 

regulators, academics, environmental 

groups, and many other stakeholders. 

Initial recommendations were issued by 

the subcommittee on August 18, 2011. 

Among other things, the report 

recommended that more information be 

provided to the public, including 

disclosure of the chemicals used in 

fracturing fluids. The subcommittee also 

recommended the adoption of 

progressive standards for wellbore 

construction and testing. 

The final report, issued on November 

18, 2011, recommended, among other 

things, that operators and regulating 

agencies ‘‘adopt best practices in well 

development and construction, 

especially casing, cementing, and 

pressure management. Pressure testing 

of cemented casing and state-of-the-art 

cement bond logs should be used to 

confirm formation isolation. Regulations 

and inspections are needed to confirm 

that operators have taken prompt action 

to repair defective cementing jobs. The 

regulation of shale gas development 

should include inspections at safetycritical stages of well construction and 

hydraulic fracturing.’’ 14

Public Concern 

The public and various groups have 

expressed strong concerns about the 

prevalence of hydraulic fracturing and 

the chemical content of the fluids used 

in the process. Some of the comments 

frequently heard during the public 

forums previously discussed included 

concerns about water quality, water 

consumption, and a desire for improved 

environmental safeguards for surface 

operations. Commenters also strongly 

encouraged the agency to require public 

disclosure of the chemicals used in 

hydraulic fracturing operations on 

Federal and tribal lands. 

Improving Governmental Processes 

The BLM has existing regulations for 

hydraulic fracturing, found in 43 CFR 

3162.3–2. Under that regulatory 

provision, an operator must seek 

approval from the BLM before 

performing ‘‘non-routine’’ fracturing 

operations. Conversely, an operator 

performing ‘‘routine’’ fracturing 

operations does not currently need the 

BLM’s approval. The regulation makes a 

distinction between ‘‘routine’’ and 

‘‘non-routine’’ fracturing operations, but 

it does not define them. This omission 

makes the distinction functionally 

difficult to apply and confusing for both 

the agency and the regulated public. 

Also, hydraulic fracturing operations 

conducted now are vastly different than 

the operations conducted decades ago. 

For decades, hydraulic fracturing was a 

completion or re-completion technology 

that used relatively small quantities of 

fluid to improve the flow of 

hydrocarbons around the bottom of 

conventional wells. Due to advances in 

horizontal drilling, hydraulic fracturing 

operations are now conducted on wells 

with longer lateral legs (often 1 to 2 

miles) and require far larger volumes of 

water. The chemical content of the 

hydraulic fracturing fluids is also a 

growing concern to the public, such that 

many state regulatory authorities now 

require the chemical disclosure of 

fracturing fluids. The information that 

the BLM currently requires before and 

after fracturing operations is inadequate 

and does not reflect the complex nature 

of the operations. 

From a resource management 

perspective, the current regulation 

results in incomplete information being 

provided to the BLM. That lack of 

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information restricts the BLM’s ability 

as the resource manager to make 

informed resource decisions about 

hydraulic fracturing operations or to 

respond effectively to incidents that 

may occur. Knowledge of the hydraulic 

fracturing operations will help the BLM 

better manage and protect public and 

tribal resources. 

Potential for Externalities 

Generally, there is greater potential 

for undesirable events or incidents to 

occur when operations are conducted in 

wells that are constructed improperly, 

where the plans are inadequate, or when 

the fluids are not properly managed. 

This potential extends to hydraulic 

fracturing operations, where the well 

may extend laterally and for longer 

distances, greater pressures are placed 

on the well, and larger volumes of fluids 

are used and recovered. As with all 

drilling and production activities, there 

is a potential that they may pose a 

negative externality to society, 

considering limitations in 

understanding the extent of potential 

damage or determining a causal 

relationship between the operation and 

the damage. 

Relative to wells constructed with 

sufficient and demonstrated integrity, 

wells that are inadequately constructed 

may not sufficiently isolate formation 

gas or fluids from water resources or 

may be more likely to fail during 

fracturing operations. Although 

wellbore integrity provisions exist in 

current BLM regulations, this rule 

would enhance those provisions to 

account for advances in technology and 

hydraulic fracturing operations. In 

addition, the recovered fluid from 

hydraulic fracturing operations may 

pose additional risk to the surface and 

subsurface environments if not managed 

and disposed of properly. 

Estimating Benefits and Costs 

After reviewing the requirements of 

the final rule, we have determined that 

it will not have an annual effect on the 

economy of $100 million or more or 

adversely affect in a material way the 

economy, a sector of the economy, 

productivity, competition, jobs, the 

environment, public health or safety, or 

state, local, or tribal governments or 

communities. Additionally, we have 

determined that it would not have a 

significant economic impact on a 

substantial number of small entities. 

Many of the requirements are 

currently met by operators as a matter 

of standard industry practice or in 

compliance with existing state 

regulations or other BLM regulations 

(including Onshore Oil and Gas Orders 

No. 1 and No. 2). We measure the 

incremental burden to operators against 

that baseline. While some requirements 

do not pose an additional burden, other 

requirements will pose an additional 

burden. 

We estimate that the rule will impact 

about 2,800 hydraulic fracturing 

operations per year, but that it could 

impact up to 3,800 operations per year 

based on previous levels of activity on 

Federal lands and growing activity on 

Indian lands. We estimate that the 

compliance cost could reach about 

$11,400 per operation or $32 million per 

year. The estimated per-operation 

compliance costs represent about 0.13 to 

0.21 percent of the cost of drilling a 

well. Given the potential to impact 

3,800 operations per year, the 

compliance costs might reach $45 

million per year. 

The BLM estimated or described the 

potential costs and benefits that would 

occur as a result of the rule. As such, it 

analyzes the impacts in relation to the 

current operating environment (or the 

baseline). In analyzing costs and 

benefits, it is important to differentiate 

between the activities that an operator 

conducts (either voluntarily or in 

compliance with state or Federal 

requirements) and those new activities 

that the rule would compel. 

Office of Management and Budget 

(OMB) Circular A–4 recognizes that not 

all benefits and costs can be described 

in monetary or even in quantitative 

terms. In those cases, it directs agencies 

to present any relevant quantitative 

information along with a description of 

the unquantified effects. 

We use a bottom-up approach to 

measure the incremental impacts rather 

than a top-down approach. In doing so, 

the BLM estimates the number of 

hydraulic fracturing operations per year 

for future years, determines the 

applicability of the requirements on the 

operations, determines the unit cost of 

compliance per requirement, and then 

calculates the total costs across all 

requirements and operations. Due to the 

uncertainty of the hydraulic fracturing 

activity in future years, the BLM 

presents a range of costs based on the 

range of potential activity. We chose to 

use a bottom-up approach because a 

requirement may not pose an 

incremental compliance cost, depending 

on the operators’ voluntary compliance 

(generally determined as whether the 

requirement is consistent with industry 

guidance or best practice) or the 

regulatory requirements in the 

jurisdiction within which the operation 

will occur. 

The BLM’s approach to estimating the 

number of hydraulic fracturing 

operations is described in the Economic 

Analysis for this rule, which is available 

from the BLM at the address listed in 

the ADDRESSES section of this rule. The 

BLM took the number of well 

completions on Federal and Indian 

lands for FY 2010 to FY 2013, and 

assumed that 90 percent of wells were 

completed using hydraulic fracturing 

and that 3 percent of those wells would 

be recompleted. The BLM then used the 

results from that 4-year period to 

forecast 3 future years of 

implementation over a 3-year period in 

the future, resulting in an estimate of 

about 2,815 hydraulic fracturing 

operations on Federal and Indian lands 

per year. 

For the annual estimate of 

completions using hydraulic fracturing, 

the BLM uses the 3-year average of the 

implementation years within each state 

and reservation. Recognizing the dip in 

well completions on Federal lands in 

FY 2013, and recognizing that previous 

levels of activity were higher, the BLM 

also calculated costs using the FY 2012 

level of activity on Federal lands, prior 

to the FY 2013 decrease, and presents 

that estimate as an upper bound of 

potential costs. 

The BLM expects that operators are 

already in compliance with many of the 

rule’s requirements as a matter of 

company practice or standard industry 

practice (described in the Economic 

Analysis), or to meet state regulations 

(described in the Economic Analysis) or 

Federal regulations (described in the 

Economic Analysis). Where the rule’s 

requirements are consistent with 

industry guidance, state regulations, or 

Federal regulations, the BLM considered 

the applicability of the requirement to 

be 0 percent and the incremental impact 

to be zero. We consider partial 

applicability in areas and in situations 

where the operator is expected to 

comply voluntarily, for example, when 

a requirement costs less than the 

alternative. 

Measuring the Incremental Costs 

Application Requirement: The 

operator must submit an application to 

conduct a hydraulic fracturing operation 

with the APD or an NOI when it plans 

to hydraulically fracture a well for 

which it has: 

• Not yet submitted an APD as of the 

effective date of this rule; 

• Submitted an APD, but the APD has 

yet to be approved as of the effective 

date of this rule; 

• An approved APD or APD 

extension on the effective date of this 

rule, drilling did not begin until after 

the effective date, and does not conduct 

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15The cost formulation for administrative 

requirements is detailed in the supporting 

statement for the Paperwork Reduction Act. 

hydraulic fracturing within 90 days after 

the effective date; 

• Started (but does not complete) 

drilling before the effective date and 

does not conduct hydraulic fracturing 

within 90 days after the effective date; 

• Completed drilling 180 days prior 

to the effective date, and does not 

conduct hydraulic fracturing within 90 

days after the effective date; or 

• Completed drilling 180 or more 

days prior to the effective date. 

The operator may also submit an 

application for a group of wells as part 

of an MHFP, thus reducing the number 

of potential applications. 

This is a new requirement and poses 

an incremental burden to the operator 

and the BLM. The information required 

in the application should be readily 

available or known to the operator. The 

information should not require any 

additional information gathering. An 

MHFP will allow for efficiencies in 

submission and review. 

The BLM expects there to be fewer 

applications than there are hydraulic 

fracturing operations, because of the 

option to make one submission for a 

group of wells, a process which is 

designed to achieve additional 

efficiencies. 

The BLM estimates the applicability 

of this requirement based on the number 

of well completions using hydraulic 

fracturing that we expect to occur. Since 

the BLM assumes that every hydraulic 

fracturing operation will require an 

application, our estimate is inclusive of 

all instances described in the first 

paragraph of this section (and 

particularly in bullets 3 through 6) 

where an operator would be required to 

submit an application to conduct 

hydraulic fracturing. 

The data are as follows: 

(a) Applicability of requirement = 100 

percent of operations. Although the 

BLM allows for the operator to submit 

a single NOI covering a group of wells, 

it is uncertain whether the operator will 

prefer that method over submitting an 

application with the APD. For the 

purpose of this analysis, the BLM 

assumes that the operator will submit an 

application for a single well, especially 

in the near-term future. 

(b) Cost per application = $643. The 

cost per application includes the 

operator burden and the BLM burden. 

For both burdens, the BLM estimates the 

compliance or review hours and the 

respective wage. The compliance cost 

for the operator is estimated to be about 

$496 per application (calculated as 8 

hours at about $61.99 per hour). The 

review cost for the BLM is estimated to 

be about $147 per application 

(calculated as 4 hours at about $36.66 

per hour).15 Some commenters stated 

that the additional informational 

requirements would cause additional 

delays in the processing of APDs and 

thus constitute an opportunity cost on 

the operator. This argument is not 

supported. The supporting statement for 

the Paperwork Reduction Act estimates 

only 4 hours of additional review time 

for the BLM to review this information. 

This does not present a measureable 

delay in processing time, and no 

revisions were made to the cost estimate 

on that basis. 

Usable Water Requirement: The 

operator must isolate all usable water 

and other mineral-bearing formations 

and protect them from contamination. 

Usable water means generally those 

waters containing up to 10,000 ppm of 

TDS. Usable water includes, but is not 

limited to: (i) Underground water that 

meets the definition of ‘‘underground 

source of drinking water’’ as defined at 

40 CFR 144.3; (ii) Underground sources 

of drinking water under the law of the 

state (for Federal lands) or tribe (for 

Indian lands); and (iii) Water in zones 

designated by the state (for Federal 

lands) or tribe (for Indian lands) as 

requiring isolation or protection from 

hydraulic fracturing operations. 

The following geologic zones are 

deemed not to contain usable water: 

(i) Zones from which an operator is 

authorized to produce hydrocarbons 

provided that the operator has obtained 

all other authorizations required by the 

EPA, the State (for Federal lands), or the 

tribe (for Indian lands) to conduct 

hydraulic fracturing operations in the 

specific zone; 

(ii) Zones designated as exempted 

aquifers under 40 CFR 144.7; and 

(iii) Zones that do not meet the 

definition of underground source of 

drinking water at 40 CFR 144.3 which 

the state (for Federal lands) or the tribe 

(for Indian lands) has designated as 

exempt from any requirement to be 

isolated or protected from hydraulic 

fracturing operations. 

This requirement does not pose an 

incremental cost. The term usable water 

is defined in a manner consistent with 

existing BLM requirements in Onshore 

Oil and Gas Order No. 2, Drilling 

Operations on Federal and Indian Oil 

and gas leases (53 FR 46798) (Onshore 

Order 2). Onshore Order 2 section III.B. 

requires casing and cement to ‘‘protect 

and/or isolate all usable water zones.’’ 

Onshore Order 2 defines ‘‘isolate’’ as 

‘‘using cement to protect, separate, or 

segregate usable water and mineral 

resources’’ (section II.I.) and ‘‘usable 

water’’ as ‘‘generally those waters 

containing up to 10,000 ppm of total 

dissolved solids’’ (section II.Y.). 

Onshore Order 2 has been in effect since 

1988; therefore, the requirement to 

protect and/or isolate usable water 

generally containing up to 10,000 ppm 

of TDS has been in effect since that 

time. This rule corrects the 

inconsistency between the definition in 

Onshore Order 2 (the definition in 

effect) and the definition in the existing 

43 CFR 3162.5–2(d). The definition in 

the CFR, of a 5,000 ppm standard, was 

superseded by the Onshore Order 2 

definition in 1998. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

Cement Monitoring Requirement: 

During cementing operations on any 

casing used to isolate usable water 

zones, the operator must monitor and 

record the flow rate, density, and pump 

pressure and submit a cement operation 

monitoring report, including this 

information, to the authorized officer 

prior to commencing hydraulic 

fracturing operations. For wells drilled 

prior to the effective date of the rule, the 

operator is required to provide 

documentation that demonstrates that 

the well is adequately cemented. 

This requirement does not pose an 

incremental cost. API Guidance 

Document HF1 stresses the importance 

of using data from reports, logs, and 

tests to evaluate the quality of a cement 

job, including drilling reports, drilling 

fluid reports, cement design and related 

laboratory reports, etc. Based on this 

information and our observations of 

field operations, the BLM believes that 

operators monitor cementing operations 

as a matter of practice and can easily 

provide this information to the 

authorized officer prior to conducting 

hydraulic fracturing. The administrative 

burden of providing this information to 

the BLM is contained in the application 

requirement. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

Surface Casing Requirements: The 

operator must observe cement returns to 

the surface and document any 

indications of inadequate cement (such 

as, but not limited to, lost returns, 

cement channeling, gas cut mud, failure 

of equipment, or fallback from the 

surface exceeding 10 percent of surface 

casing setting depth, or 200 feet, 

whichever is less). If there are 

indications of inadequate cement, then 

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16 Ibid, p. 8. 

17 Ibid, p. 9. 

18 Ibid, p. 10. 

the operator must determine the top of 

the cement with a CEL, temperature log, 

or other method or device approved by 

the authorized officer. 

This requirement does not pose an 

incremental cost. Onshore Order 2 

requires the operator to return cement to 

the surface (section II.B.1.c.). 

Documenting indications of adequate 

cement and taking corrective action are 

necessary responses when such issues 

arise. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

CEL on Intermediate Casing that 

Protects Usable Water: If the operator 

does not cement the intermediate casing 

string to surface and the intermediate 

casing is used to isolate usable water, 

then the operator must run a CEL to 

demonstrate that there is at least 200 

feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. 

This requirement might pose an 

additional burden to the operator. API 

Guidance Document HF1 stresses the 

importance of using data from reports, 

logs, and tests to evaluate the quality of 

a cement job. According to the 

guidance, well logging is a common 

practice of operators and may be 

conducted multiple times while drilling 

a well. ‘‘Well logs are critical data 

gathering tools used in formation 

evaluation, well design, and 

construction.’’ 16 A cement bond log 

‘‘measures the presence of cement and 

the quality of the cement bond or seal 

between the casing and the 

formation.’’ 17 Logs are important in 

‘‘determining that the well drilling 

construction is adequate and achieves 

the desired design objectives.’’ 18 It is 

industry practice to run logs on the 

production casing of wells. For the 

intermediate casing, if cement is not 

circulated to the surface, operators may 

run a CEL or other diagnostic tools to 

determine the adequacy of the cement 

integrity and that the cement reached 

the desired height (above any exposed 

USDW or any hydrocarbon bearing 

zone). State requirements of conditions 

of the drilling permit may also 

necessitate the running of logs on the 

intermediate casing. 

Generally, the BLM expects that the 

operator would log the intermediate 

casing to ensure that the well was 

constructed according to design. 

Logging the casing may also be 

warranted if the operator plans to hang 

a production liner off of the 

intermediate casing, if the proposed 

fracturing is through the intermediate 

casing, for hole stability, for isolation 

through salt zones, or for isolation 

through disposal zones. 

Some states require logging of the 

intermediate casing through regulation 

in a manner that is consistent with this 

rule. North Dakota requires a CBL on the 

intermediate casing; Colorado requires a 

CBL if the operator uses a production 

liner; and Texas specifies that the 

operator must identify the top of cement 

(with a CBL or temperature log) if it 

does not cement to the surface. 

California and Wyoming may require it 

in certain circumstances. Additionally, 

the BLM and states may require 

operators to log the intermediate casing 

as a condition of approval if, for 

example, any of the conditions in the 

previous paragraph apply. Industry 

guidance states that operators may run 

a CBL and/or other diagnostic tools to 

determine the adequacy of the cement 

integrity and that the cement reached 

the desired height. 

The rule requires that the operator 

demonstrate that there is at least 200 

feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. When the operator does not 

circulate cement to the surface, it will 

most often comply with this 

requirement by running a CEL on the 

production casing (when the operator is 

conducting hydraulic fracturing through 

the production string). That process is 

described later. However, if the operator 

plans to conduct the fracturing 

operation through a production liner 

that is hung from the intermediate 

casing, then it must either circulate the 

cement behind the intermediate string 

to surface or run a CEL on the 

intermediate casing string. Although we 

believe that this requirement is 

consistent with prudent operations, the 

intent of the industry guidance, other 

state regulations, and conditions of 

approval that the BLM generally places 

on APDs where the operator uses a 

production liner hung from the 

intermediate casing, we recognize that, 

in some cases, the rule would compel 

the operator to run a CEL when it would 

not have done so otherwise. 

The BLM does not have credible data 

on the prevalence of voluntary 

compliance or the prevalence of CEL 

requirements as conditions of approval. 

The BLM assumes that the rule will 

compel new action for all operations in 

states without existing regulations 

requiring a CEL of the intermediate 

casing. The BLM also recognizes that, as 

a result of this assumption, the cost 

estimates will be overstated. 

(a) Applicability of requirement = 0 

percent of operations in ND and CO; 2.5 

percent in TX ; and 5 percent in other 

states. Based on field experience, the 

BLM anticipates that only about 5 

percent of wells have intermediate 

casing to protect usable water. 

(b) Incremental cost per requirement = 

$111,200. After the operator cements the 

intermediate casing, it must wait a 

number of hours for the cement to 

harden before commencing drilling 

operations. After that time, the operator 

will pressure test the casing, drill out, 

and perform a leak-off test. The BLM 

received some comments indicating that 

a CEL test necessitates that the cement 

harden for 72 hours. These comments 

do not take into consideration the time 

that the operator must wait to perform 

other well tests. The BLM also notes 

that operators generally use additives to 

speed up the hardening of cement 

behind intermediate casing. For the 

purpose of our analysis, the BLM 

considers only the additional wait time 

required for the CEL, accounting for 48 

hours of additional time at a cost of 

$1,900 per hour. The cost for a CEL on 

the intermediate casing includes the test 

($20,000) and the cost of maintaining 

idle drilling equipment on-site 

($91,200). The BLM believes that 48 

hours is the upper bound of the 

potential cost. In addition, the operator 

could potentially avoid delays in part or 

entirely by running the CEL at some 

point while drilling the production 

casing. 

CEL on Production Casing that 

Protects Usable Water: If the operator 

does not cement the production casing 

string to the surface, then the operator 

must run a cement evaluation log to 

demonstrate that there is at least 200 

feet of adequately-bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. 

This requirement does not pose an 

incremental cost. API Guidance 

Document HF1 indicates that operators 

run a log to evaluate the quality of the 

cement bond on the production casing 

as a matter of industry practice. This is 

consistent with observations of field 

operations. Colorado and North Dakota 

require a CBL in their regulations. Texas 

specifies that the operator must identify 

the top of cement (with a CBL or 

temperature log) if it does not cement to 

the surface. California and Wyoming 

may require it under certain 

circumstances. In states that do not 

specify a requirement in their 

regulations, the BLM still expects that 

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16198 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

19Percent range cited by George King, a 

petroleum engineer for Apache Corporation (Behr, 

P. (October 1, 2012). Safety of shale gas wells is up 

to the states—and the ‘cement job’. EnergyWire). 

That range is consistent with a survey of 

enforcement actions conducted by the Energy 

Institute (Groat, C. & Grimshaw, T. (February 2012). 

Fact-based regulation for environmental protection 

in shale gas development. The Energy Institute, p. 

16). 20API Guidance Document HF1, p. 21. 

the operator to run a CEL as a matter of 

practice. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

Corrective Action Requirement: On all 

casing strings where the operator 

cements to the surface, the operator 

must document any indications of 

inadequate cement (such as, but not 

limited to, lost returns, cement 

channeling, gas cut mud, failure of 

equipment, or fallback from the surface 

exceeding 10 percent of surface casing 

setting depth or 200 feet, whichever is 

less). If there are indications of 

inadequate cement, then the operator 

must: 

• Notify the authorized officer within 

24 hours of discovering the inadequate 

cement; 

• Submit an NOI to the authorized 

officer requesting approval of a plan to 

perform remedial action to achieve 

adequate cement. In emergencies or in 

situations of an immediate nature that 

may result in unnecessary delays, the 

operator may request oral approval from 

the authorized officer for actions to be 

undertaken to remediate the cement and 

follow-up with a written notice 

afterwards; 

• Verify that the remedial action was 

successful with a CEL or other method 

approved in advance by the authorized 

officer; and 

• Submit a subsequent report for the 

remedial action including a signed 

certification that the operator corrected 

the inadequate cement job in 

accordance with the approved plan with 

the results from the CEL or other 

approved test. 

This requirement poses an 

administrative burden, but not an 

operational burden. The BLM and many 

state regulations and requirements have 

established protocol for remedial 

actions in the event of inadequate 

cementing, which require operators to 

remediate and/or take action as directed 

by the regulatory authority. For 

example, Onshore Order 2 requires that 

operators perform remedial cementing if 

cement is not circulated back to the 

surface for the surface casing (section 

III.B.1.c.). Onshore Order 2 also requires 

an additional pressure test and/or 

remedial action as specified by the 

authorized officer if a pressure test 

indicates that casing strings do not meet 

minimum standards (section III.B.1.h.). 

The BLM believes that this requirement 

will impose an administrative burden 

on the operator who observes 

indications of inadequate cementing, 

but not an operational burden. In the 

supplemental proposed rule, the BLM 

had specified that the operator would 

have to run a CEL to demonstrate that 

the remedial action was successful, but 

the final rule’s requirement is that the 

operator may use a CEL or other 

approved test, presumably a 

temperature log, that would not result in 

delays. 

(a) Applicability of requirement = 3 

percent of operations. The number of 

wells where there is an indication that 

the initial cement jobs require repairs is 

generally believed to be between 1 

percent and 5 percent.19 The BLM uses 

the midpoint of the range, or 3 percent, 

and applies it to the number of newly 

drilled wells for the activity data. 

(b) Cost per response = $643. Burden 

includes the operator burden and the 

BLM burden. The compliance cost for 

the operator is estimated to be about 

$496 per application (calculated as 8 

hours at about $61.99 per hour). The 

review cost for the BLM is estimated to 

be about $147 per application 

(calculated as 4 hours at about $36.66 

per hour). 

Mechanical Integrity Test 

Requirement: If hydraulic fracturing 

through the casing is proposed, the 

operator must test the casing to not less 

than the maximum anticipated surface 

pressure that will be applied during the 

hydraulic fracturing process. If 

hydraulic fracturing through a fracturing 

string is proposed, then the operator 

must test the fracturing string to not less 

than the maximum anticipated surface 

pressure minus the annulus pressure 

applied between the fracturing string 

and the production or intermediate 

casing. 

This requirement does not pose an 

incremental cost. Industry guidance and 

state regulations are consistent with this 

requirement. Industry guidance on 

hydraulic fracturing states that the 

production casing of a well should be 

pressure tested prior to completion. The 

BLM also reviewed state regulations in 

California, Colorado, Montana, New 

Mexico, North Dakota, Oklahoma, 

Texas, Utah, and Wyoming. From FY 

2010 to FY 2013, the number of well 

completions on Federal and Indian 

lands in those states accounted for 99.3 

percent of the total well completions on 

Federal and Indian lands nationwide. 

The state regulations in those states 

either require pressure tests on all 

casing strings or on the casing strings 

through which the completion operation 

will occur. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

Monitor Annulus Pressures and 

Reporting Requirement: During the 

operation, the operator must 

continuously monitor and record the 

annulus pressures at the bradenhead 

and between any intermediate casings 

and the production casing. The operator 

must submit a continuous record of all 

annuli pressure during the fracturing 

operation in the subsequent report. If 

during any hydraulic fracturing 

operation any annulus pressure 

increases by more than 500 psi as 

compared to the pressure immediately 

preceding the stimulation, the operator 

must take immediate corrective action 

and orally notify the authorized officer 

as soon as practical, but no later than 24 

hours following the incident. Within 30 

days after the hydraulic fracturing 

operations are completed, the operator 

must submit a report containing all 

details pertaining to the incident, 

including corrective actions taken, as 

part of a subsequent report. 

This requirement does not pose an 

incremental cost. API Guidance 

Document HF1 says that if the annular 

space is not cemented to the surface, 

then operators should monitor pressures 

in the annulus between the production 

casing and the intermediate casing. 

‘‘Pressure is normally measured at the 

pump and in the pipe that connects the 

pump to the wellhead. If the annulus 

between the production casing and the 

intermediate casing has not been 

cemented to the surface, the pressure in 

the annular space should be monitored 

and controlled. Pressure behavior 

throughout the hydraulic fracture 

treatment should be monitored so that 

any unexplained deviation from the 

pretreatment design can be immediately 

detected and analyzed before operations 

continue . . . Unexpected or unusual 

pressure behavior during the hydraulic 

fracturing process could indicate some 

type of problem.’’ 20 Based on this 

information and our observations of 

field operations, we believe that 

operators monitor annulus pressures 

during hydraulic fracturing operations 

as a matter of practice and can easily 

provide this information to the 

authorized officer after conducting 

hydraulic fracturing. The administrative 

burden of providing this information to 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16199 

21Center for Sustainable Shale Development Web 

site. Accessed on March 29, 2013, http://

037186e.netsolhost.com/site/performancestandards/. 

22A map of designated Surface Water Supply 

Areas, accessed on May 27, 2014, is available at 

http://cogcc.state.co.us/rulemaking/

FinalDraftRules/CDPHE317B_Map.pdf. 

23The comment letter from ConocoPhillips, dated 

August 22, 2013, is available in the rulemaking 

docket at www.regulations.gov. 

the BLM is contained in the postfracturing reporting requirements. 

(a) Applicability of requirement = 0 

percent of operations 

(b) Incremental cost per requirement = 

$0 

Storage Tank Requirement: The 

operator must manage recovered fluid in 

‘‘rigid enclosed, covered or netted and 

screened above-ground tanks.’’ The 

tanks may be vented, unless Federal 

law, or state regulations (on Federal 

lands) or tribal regulations (on Indian 

lands) require vapor recovery or closedloop systems. The tanks are also limited 

in size to 500 bbl of capacity or less. 

Under certain limited circumstances, 

the operator may seek approval to use 

a lined pit with a leak detection system. 

This is a new requirement and could 

pose an incremental burden to the 

operator depending on the size and 

specifics of the operation, and whether 

the management of recovered fluids in 

tanks is already required by the state or 

tribe. Although API Guidance Document 

HF2 does not specify the use of rigid 

above-ground tanks to manage 

recovered fluids from hydraulic 

fracturing operations, our observations 

of field operations indicate that the use 

of rigid above-ground tanks for receiving 

recovered fluids is very common, 

regardless of the state’s requirements. 

These tanks are commonly referred to as 

‘‘frac tanks,’’ constructed of steel, and 

have a holding capacity of up to 21,000 

gallons, or 500 bbl, of fluid. The tanks 

are generally limited to that capacity or 

size due to their transportability on 

surface roads to and from a well site. 

Enclosed tanks are generally provided 

with anti-burst air vents to vent 

pressurized gas to prevent safety 

hazards or they may be connected to a 

system that collects the pressurized gas 

for sale or combustion. Some tanks of 

the same size specifications, steel 

construction, and rigidity, may have 

open tops that allow the operator to 

more easily inspect the flowback 

visually, pump out fluids, and vacuum 

out the proppants. 

The rule prohibits the use of other 

larger-volume above-ground semi-rigid 

tanks (with a capacity of up to 40,000 

bbl) for managing recovered fluids. 

These tanks are ‘‘semi-rigid,’’ because 

they are constructed of steel sections 

and assembled on-site. These tanks are 

rarely used for managing flowback 

directly and are more often used for 

holding fresh water before the hydraulic 

fracturing operation and sometimes for 

holding water after it has been separated 

and treated after hydraulic fracturing 

operations. 

The use of rigid steel tanks to manage 

recovered fluids tends to vary by 

operator and the regions in which they 

operate. These tanks are particularly 

prevalent in the Eastern U.S. and are 

being incorporated into model standards 

for shale development.21 Among 

Western states, where development on 

Federal and Indian lands is most 

prevalent, New Mexico and Texas 

generally require storage tanks, but 

allow operators to apply for permits to 

use pits. Colorado requires storage tanks 

in Surface Water Supply Areas.22

Our observations of field operations 

in the Western states lend evidence to 

the widespread use of steel rigid tanks 

to manage recovered fluids from 

hydraulic fracturing operations in those 

states. Further, by examining the 

expected volume of recovered fluids, 

and the relative costs of using storage 

tanks versus a pit for these volumes, the 

BLM believes that the use of storage 

tanks often will cost less than pits for 

operations on Federal and Indian lands 

as discussed in more detail below. 

In the supplemental proposed rule, 

the BLM solicited comment concerning 

the incremental costs of a requirement 

to manage recovered fluids with tanks 

instead of lined pits. 

One commenter supported the broad 

use of steel tanks, but recommended 

that the BLM not require closed-loop 

systems, citing concerns about costs, the 

pressurization of gas, and ability to 

make visual inspections of the fluid, the 

advantage of maintaining flexibility 

depending on the operations or 

conditions, and the EPA’s regulations 

covering emissions from storage tanks. It 

also supported the option of potentially 

using larger volume atmospheric tanks 

and lined impoundments (or pits), both 

with secondary containment and leak 

detection systems, for large volume 

hydraulic fracturing operations.23

The commenter estimated the costs of 

steel tanks, semi-rigid tanks, and pits 

over a 5-year period (using a present 

discounted value approach and a 10 

percent discount rate) for multiple 

operations, with a cumulative total 

capacity of about 250,000 bbl. It 

estimated the costs of an engineered 

impoundment to be $2.3 million, semirigid tanks to be $2.42 million, and steel 

tanks to be $23 million, all over a 5-year 

period (see Table 5). 

TABLE 5—COMMENTER COST ESTIMATES FOR MANAGING RECOVERED FLUIDS

Engineered 

impoundment Semi-rigid steel tanks Steel tanks 

Number of impoundments or tanks .......................................... 1 6 .............................................. 500 

Impoundment or tank capacity (bbl) ......................................... 250,000 40,000 ..................................... 500 

Total capacity (bbl) ................................................................... 250,000 240,000 ................................... 250,000 

Initial construction or set up-take down cost ............................ $2,970,000 $51,000 × 6 = $306,000 ......... n/a 

Annual operating or Rental Cost .............................................. $20,000 $132,000 × 6 = $792,000 (assumes $11,000 monthly 

rental fee).

$16,425 × 500 = $8,212,500 

(assumes $45 daily rental 

fee) 

5-Year net present value (NPV) (at 10%) ................................ $2,300,000 $2,420,000 .............................. $23,000,000 

In reviewing these data, it would be 

inappropriate to conclude simply that 

using steel tanks would cost 10 times 

more than a pit. The commenter did not 

specify the number of hydraulic 

fracturing operations that a pit, or 

deployment of semi-rigid tanks or rigid 

steel tanks, might service over the 5-year 

period. The BLM expects that while 

each method could service the same 

number of hydraulic fracturing 

operations at the same general location, 

pits are limited to a single geographic 

location, but tanks are portable and can 

be deployed at different geographic 

locations over the 5-year period, thereby 

servicing a larger number of operations 

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16200 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

24Skytruth.org, ‘‘2013 Reports Data,’’ accessed on 

November 20, 2014. 

25EPA Web site, ‘‘Hydraulic Fracturing Research 

Study,’’ accessed on November 20, 2014 at http:// 

www.epa.gov/ogwdw000/uic/pdfs/hfresearch

studyfs.pdf. 

26Halliburton, ‘‘Produced and Flowback Water 

Recycling and Reuse: Economics, Limitations, and 

Technology,’’ accessed on November 25, 2014 at 

http://www.halliburton.com/public/multichem/

contents/Papers_and_Articles/web/Feb-2014-OilGas-Facilities-Article.pdf. 

and reducing the per-operation cost of 

using tanks over that time period. 

We also note that the transportability 

and severability of 500 steel tanks allow 

an operator to service multiple 

operations in different locations at the 

same time. For example, 500 steel tanks 

could service 5 large operations (of 100 

steel tanks each) concurrently in 

different geographic locations. 

The BLM received other comments 

about the incremental costs of requiring 

storage tanks. A commenter’s analysis 

suggested a tank requirement would 

pose an incremental cost of $5,500 per 

operation or $19.6 million for the 

industry per year. Another commenter 

suggested that an open pit costs 

$447,000 and a closed-loop system costs 

$267,000 (an $180,000 cost advantage). 

The BLM did not receive comments 

on the prevalence of voluntary 

compliance among operations or across 

operations, though the first commenter 

supported the broad use of storage tanks 

and the potential option to use larger 

tanks or pits. The BLM would generally 

expect that an operator would choose to 

use steel tanks voluntarily (when 

otherwise not compelled to do so by 

regulation, condition of approval, 

environmental consideration, or 

company practice) in situations where 

tanks would cost the same as or less 

than pits, and this may be largely 

dependent on the volume of recovered 

fluids expected. 

The amount of water used to 

hydraulically fracture a well and the 

amount of fluid recovered from the 

operations vary depending on the 

formation and the operation itself. The 

BLM examined data extracted from 

FracFocus 24 for wells completed in 

2013, shown in Figure 3. The data show 

that the average volume of water used 

for the hydraulic fracturing operations 

was 60,279 bbl (or more than 2.5 million 

gallons). The BLM used the number of 

well completions on Federal and Indian 

lands from FY 2010–FY 2013 to develop 

a weighted average for hydraulic 

fracturing operations on Federal and 

Indian lands. Shown in Figure 3, the 

BLM would expect the average volume 

of water used for hydraulic fracturing 

operations on Federal and Indian lands 

to be 24,385 bbl (or more than 1 million 

gallons). 

FIGURE 3—AVERAGE WATER USED IN HYDRAULIC FRACTURING OPERATIONS, 2013, AND ESTIMATED RECOVERED FLUIDS

State 

Average 

volume of 

water used 

(bbl) 

(data extracted 

from 

FracFocus) 

Range of recovered fluids (bbl) 

Low (15%) High (40%) 

Alaska .......................................................................................................................................... 2,343 351 937 

Arkansas ...................................................................................................................................... 203,648 30,547 81,459 

California ...................................................................................................................................... 2,375 356 950 

Colorado ...................................................................................................................................... 52,013 7,802 20,805 

Kansas ......................................................................................................................................... 35,373 5,306 14,149 

Louisiana ...................................................................................................................................... 89,333 13,400 35,733 

Mississippi .................................................................................................................................... 111,500 16,725 44,600 

Montana ....................................................................................................................................... 50,058 7,509 20,023 

New Mexico ................................................................................................................................. 19,110 2,866 7,644 

North Dakota ................................................................................................................................ 56,535 8,480 22,614 

Ohio ............................................................................................................................................. 107,855 16,178 43,142 

Oklahoma ..................................................................................................................................... 78,600 11,790 31,440 

Pennsylvania ................................................................................................................................ 128,122 19,218 51,249 

South Dakota ............................................................................................................................... 61,227 9,184 24,491 

Texas ........................................................................................................................................... 61,412 9,212 24,565 

Utah ............................................................................................................................................. 8,885 1,333 3,554 

Virginia ......................................................................................................................................... 706 106 282 

Washington .................................................................................................................................. 23,264 3,490 9,306 

West Virginia ................................................................................................................................ 143,873 21,581 57,549 

Wyoming ...................................................................................................................................... 17,397 2,610 6,959 

Weighted Average (based on the operations in the dataset) ..................................................... 60,278 9,042 24,111 

Weighted Average (based on average volume of the operations by state and the distribution 

of operations on Federal and Indian lands) ............................................................................. 24,385 3,658 9,754 

Note: There were no data in the FracFocus extraction for Alabama and Nevada, which had a total of only seven well completions from FY 

2010–FY 2013. 

The data extracted from FracFocus do 

not show the amount of fluid recovered 

from the operations. The EPA indicates 

that this amount may range widely from 

15 percent to 80 percent of the original 

amount injected, depending on the 

site.25 Halliburton lists ranges for fluid 

recovery for popular producing areas 

that are more modest, as follows: 26

• Bakken: 15–40 percent 

• Eagle Ford: < 15 percent 

• Permian Basin: 20–40 percent 

• Marcellus: 10–40 percent 

• Denver-Julesburg: 15–30 percent 

Figure 3 also provides the range of 

volumes expected to be recovered from 

hydraulic fracturing operations, which 

is estimated to range from 3,658 bbl (10 

percent) to 9,754 bbl (40 percent) on 

average based on the data. 

The BLM contacted service providers 

of tanks used for the management of 

fluids from hydraulic fracturing 

operations to better examine the peroperation incremental costs of using 

rigid steel tanks instead of a pit. We 

estimated the baseline cost of 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16201 

27We attempted to replicate the commenter’s 

derivation of the 5-Year NPV (at 10%) for the 

engineered impoundment in order to estimate an 

annualized value for a pit with a 7% discount rate. 

We roughly generated the commenter’s value by 

assigning one-third of the capital costs to initial 

construction (year 0) and two-thirds of the capital 

costs to the take down costs (year 5). 

constructing and operating a pit based 

on the first commenter’s data. We 

estimated the 5-year NPV (using a 

discounted rate of 7 percent) of a pit to 

be about $2,460,000, generating an 

annualized cost of about $92,000 and, 

finally, a per-operation cost of about 

$98,400, assuming a pit could service 5 

operations per year and 25 operations 

over a 5-year period.27 Using the BLM’s 

Automated Fluid Minerals Support 

System (AFMSS) well-completion data 

from January 2008 to December 2012, 

we found that operators completed an 

average of 5.067 wells in a case. 

In Table 2, we provide the general 

engineering costs for rigid steel tanks 

provided by service companies and then 

we calculate per-operation job costs 

based on the capacity number of 

potential job capacities. In addition, for 

each job capacity, we estimate the cost 

of the tank deployment for that 

operation and the incremental cost per 

operation when employed instead of a 

pit. Other assumptions include that the 

transportation to and from the site for 

steel tanks will take 4 hours, and that 

the rental period is either 14 or 21 days. 

TABLE 2—GENERAL ENGINEERING COSTS FOR STEEL RIGID TANKS PER OPERATION AND INCREMENTAL COSTS, BY JOB

CAPACITY

Engineering Costs 

Job duration (days) .................................................................................................................................................. 14 21 

Tank capacity (bbl) .................................................................................................................................................. ........................ 500 

Transportation to site ($/hr/tank) ............................................................................................................................. ........................ $120 

Rental ($/day/tank) .................................................................................................................................................. ........................ $40 

Transportation from site ($/hr/tank) ......................................................................................................................... ........................ $120 

Job Capacity (10,000 bbl) 

Tanks required ......................................................................................................................................................... 20 20 

Costs per operation ................................................................................................................................................. $30,400 $36,000 

Incremental cost instead of a pit ............................................................................................................................. ¥$68,000 ¥$62,400 

Job Capacity (30,000 bbl) 

Tanks required ......................................................................................................................................................... 60 60 

Costs per operation ................................................................................................................................................. $91,200 $108,000 

Incremental cost instead of a pit ............................................................................................................................. ¥$7,200 $9,600 

Job Capacity (50,000 bbl) 

Tanks required ......................................................................................................................................................... 100 100 

Costs per operation ................................................................................................................................................. $152,000 $180,000 

Incremental cost instead of a pit ............................................................................................................................. $53,600 $81,600 

According to the available 

information, rigid steel tanks are less 

costly than pits on smaller and medium 

volume jobs lasting 14 days (e.g., 

$68,000 and $7,200 advantage for jobs 

with capacities of 10,000 and 30,000 

bbl, respectively) and likely to be more 

costly than pits for higher-volume jobs 

(e.g., $53,600 disadvantage for jobs with 

a capacity of 50,000 bbl). For jobs 

lasting 21 days, rigid steel tanks are 

likely to be less costly than pits on jobs 

up to the job capacity threshold 

described above. 

Given the assumptions, and for a job 

lasting 14 days, the point at which the 

cost of using tanks and the cost of using 

a pit are roughly equal is when the job 

capacity is 32,368 bbl. This means that 

steel tanks would cost less for jobs 

where the volume of recovered fluids is 

less than 32,368 bbl and pits would cost 

less for jobs where the volume of 

recovered fluids is greater than 32,368 

bbl. For a job lasting 21 days, the point 

at which the cost of using tanks and the 

cost of using a pit are roughly equal is 

when the job capacity is 27,333 bbl. 

The BLM derived these thresholds 

using the following progression: 

(1) Per-operation cost of pit = Cost of 

steel tanks for an operation 

(2) Per-operation cost of pit = [Cost of 

tank transport to and from site + 

Cost of tank rental ] 

(3) Per-operation cost of pit = 

2 * [(Cost of tank transport $/hr/tank) * 

(hours) * (Job capacity/tank 

capacity)] 

+ [(Cost of rental $/day/tank) * (days) * 

(Job capacity/tank capacity)] 

(4) [Per-operation cost of pit/3.04 ] = Job 

capacity bbl; when the job duration 

is 14 days; or 

[Per-operation cost of pit/3.60 ] = Job 

capacity bbl; when the job duration 

is 21 days 

(5) Job capacity bbl = 32,368; when the 

job duration is 14 days; or 

Job capacity bbl = 27,333; when the job 

duration is 21 days 

To estimate voluntary compliance, we 

looked at the percent of operations (in 

the data extracted from FracFocus) 

where the job capacity (measured as the 

40 percent of the water used) was less 

than the thresholds of 32,368 bbl and 

27,333 bbl. 

Where the job capacity exceeded the 

threshold, the BLM assumed that the 

operators would not have voluntarily 

used storage tanks. We then calculated 

the average job capacity for operations 

above this threshold based on the 

distribution of operations on Federal 

and Indian lands. We estimate that the 

average job capacity for operations 

exceeding the thresholds is either 

47,575 or 55,631 bbl. See Table 5C. We 

note again that operators may choose to 

use steel tanks irrespective of costs, for 

example in adherence to condition of 

approvals, environmental 

considerations, company practice, etc. 

Based on that average job capacity, we 

then calculated an average incremental 

cost of using tanks instead of a pit for 

only those operations where we do not 

estimate that the operator will 

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16202 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

voluntarily comply. Assuming job 

durations lasting 14 days, we estimate 

the average incremental cost to be 

$71,840 per operation that exceeds the 

threshold of 32,368 bbl. Assuming job 

durations last 21 days, we estimate the 

average incremental cost to be $74,400 

per operation that exceeds the threshold 

of 27,333 bbl. Due to the variability of 

job durations across the U.S., we use the 

average incremental cost to be $74,400 

per operation as a basis for the cost 

estimates, recognizing that this is likely 

to both overestimate and constrain the 

potential costs. 

TABLE 5C—ESTIMATED VOLUNTARY COMPLIANCE OF A STEEL TANK REQUIREMENT AND THE AVERAGE VOLUME OF

RECOVERED FLUIDS FOR OPERATIONS WHERE THE OPERATOR IS NOT EXPECTED TO VOLUNTARILY COMPLY

State 

Job duration of 14 days Job duration of 21 days 

Estimated 

voluntary 

compliance 

(%) 

Average 

volume of 

recovered 

fluids for 

operations 

exceeding the 

threshold 

(40% recovery 

rate) 

Estimated 

voluntary 

compliance 

(%) 

Average 

volume of 

recovered 

fluids for 

operations 

exceeding the 

threshold 

(40% recovery 

rate) 

Alaska .............................................................................................................. 100.0 0 100.0 0 

Arkansas .......................................................................................................... 2.9 83,926 2.9 83,926 

California .......................................................................................................... 100.0 0 100.0 0 

Colorado .......................................................................................................... 84.7 58,980 71.7 45,616 

Kansas ............................................................................................................. 100.0 0 95.6 27,597 

Louisiana .......................................................................................................... 49.3 53,781 30.4 47,650 

Mississippi ........................................................................................................ 66.7 130,775 66.7 130,775 

Montana ........................................................................................................... 91.8 37,257 79.6 32,260 

New Mexico ..................................................................................................... 96.7 79,352 96.1 72,616 

North Dakota .................................................................................................... 86.8 50,455 75.1 40,842 

Ohio ................................................................................................................. 0.0 43,142 0.0 43,142 

Oklahoma ......................................................................................................... 68.5 63,084 61.9 57,248 

Pennsylvania .................................................................................................... 12.4 55,208 7.1 53,780 

South Dakota ................................................................................................... 100.0 0 100.0 0 

Texas ............................................................................................................... 68.2 57,699 64.3 54,663 

Utah ................................................................................................................. 100.0 0 100.0 0 

Virginia ............................................................................................................. 100.0 0 100.0 0 

Washington ...................................................................................................... 100.0 0 100.0 0

West Virginia .................................................................................................... 3.3 58,566 0.0 57,549 

Wyoming .......................................................................................................... 93.3 39,880 92.3 38,629 

Weighted Average (based on distribution of operations in FracFocus) .......... 70.3 57,283 65.4 53,398 

Weighted Average (based on distribution of operations on Federal and Indian lands) .................................................................................................... 93.5 55,631 90.6 47,757 

With respect to the applicability of 

the requirement, we estimate that the 

rule will have no impact in states with 

existing requirements for use of tanks. 

We also assume that the rule will have 

no impact where operators are expected 

to voluntarily comply with the use of 

tanks regardless of the rule (the rates of 

assumed voluntary compliance are in 

Table 5C). We assume that for all other 

states, the rule will compel action on 

100 percent of the operations, even 

though we expect that operators are 

already in compliance with the rule as 

a matter of voluntary practice. 

(a) Applicability of requirement = 0 

percent of operations in NM and TX 

based on state regulations; 0 percent in 

AK, CA, SD, UT, based on estimated 

voluntary compliance; 97.1 percent in 

AR, 28.3 percent in CO, 4.4 percent in 

KS, 69.6 percent in LA, 33.3 percent in 

MS, 20.4 percent in MT, 24.9 percent in 

ND, 100 percent in OH, 38.1 percent in 

OK, 92.9 percent in PA, and 7.7 percent 

in WY, based on estimated voluntary 

compliance; 100 percent in AL and NV, 

based on lack of validating data. We 

attribute the appropriate percentages to 

each tribe based on geographic location. 

(b) Incremental cost per operation = 

$74,400. This incremental cost is only 

for those operations where the use of 

storage tanks is not required by state 

regulations and where the operator is 

not expected to use storage tanks 

voluntarily. Operations that are most 

likely to incur this cost are in states 

where 0.8% of all oil and gas activity on 

public lands occurs. Incremental 

average costs across all operations on 

public and Indian lands are $5,544 (see 

Table 6A). Under the rule, the operator 

may request approval to use a lined pit 

that is equipped with a leak detection 

system. While Onshore Order 7 requires 

leak detection systems for produced 

water disposal pits, which may be used 

on a long-term basis, there has been no 

requirement for leak detection systems 

on temporary pits until now. According 

to BLM engineers citing analogous EPA 

data, the cost of equipping a pit with a 

leak detection system might range from 

$2 to $9 per square foot, depending on 

the sophistication of the system (EPA 

2012, Field Demonstration of Innovative 

Condition Assessment Technologies for 

Water Mains: Leak Detection and 

Location). Assuming 2,000 feet of piping 

and that a centralized pit might service 

5 operations, the per-operation cost of 

equipping a centralized pit with a leak 

detection system might be between $800 

and $3,600. Additional cost information 

for leak detection systems is available in 

the EPA Notice of Proposed Rulemaking 

for Liners and Leak Detection for 

Hazardous Waste and Land Disposal 

Units. The notice suggests that costs of 

a leak detection system would be about 

$6,100 for a half-acre pit and $6,520 for 

an acre pit. Again, that cost could be 

spread across multiple hydraulic 

fracturing operations and, assuming a 

pit services 5 completions, the peroperation cost might be $1,200 to 

$1,300. However, according to the 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16203 

28The RFF findings cited are available on its Web 

site under flowback/wastewater storage and 

disposal, accessed on May 27, 2014: http://

www.rff.org/centers/energy_economics_and_policy/

Pages/Shale_Maps.aspx. 

29API, HF2. 

specifications listed in Onshore Order 7, 

the BLM engineers also believe that the 

costs of including a leak detection 

system could be higher and generally 

comparable to using storage tanks. 

The BLM examined an alternative 

approach to the final rule. That 

alternative would have required the 

operator to manage recovered fluids in 

a lined pit, at a minimum. The 

requirement to manage recovered fluids 

in lined pits or storage tanks is 

consistent with almost all existing state 

regulations in states where new oil and 

gas activity is occurring on BLMmanaged lands. The BLM examined 

regulations in nine states where new 

drilling activity is most prevalent on 

Federal lands and found that those 

states either have existing minimum 

requirements for lined pits or storage 

tanks or that operators use lined pits or 

tanks to ensure the protection of 

groundwater. One exception, California, 

does not appear to have a statewide 

minimum requirement for lined pits, 

but such requirements may be contained 

within rules specific to particular fields 

within the state. Further, according to 

Resources for the Future (RFF), 

Alabama, Arkansas, Kansas, Louisiana, 

Mississippi, Pennsylvania, and South 

Dakota also have existing pit liner 

requirements.28 Considering the low 

level of oil and gas development on 

Federal lands in these states where 

lined pits are permitted, the impact of 

this provision is likely to be very small. 

The BLM does not have data on the pitliner requirements on Indian lands or 

the voluntary use of lined pits in 

general, as is recommended as a 

minimum standard by industry 

guidance.29 The BLM estimated the unit 

cost of lining a pit to be $6,000, using 

prices quoted by suppliers of about 

$0.24 per square foot of lining. The 

amount of lining required varies by well 

and the cost of lining depends on the 

thickness and other properties that vary 

by the use of the pit. 

(a) Applicability of requirement 

(alternative) = 0 percent of operations in 

AL, AR, CO, KS, LA, MS, MT, ND, NM, 

OK, PA, SD, TX, UT, WY; 20 percent in 

CA; 50 percent in AK, NV, OH, and 

Indian lands. 

(b) Incremental cost per operation 

(alternative) = $6,000. 

Post-Fracturing Reporting 

Requirement: The operator must submit 

information to the BLM after the 

hydraulic fracturing operation in a 

subsequent report. The operator must 

disclose the chemicals used to the BLM, 

and may use FracFocus for that 

disclosure. The operator may withhold 

formulations that are deemed to be a 

trade secret. 

This is a new requirement and poses 

an incremental burden to the operator 

and the BLM to review. The information 

required in the application should be all 

readily available or known to the 

operator. The information should not 

require any additional information 

gathering. Unlike the application, which 

may be an MHFP for a group of wells, 

the operator will submit a unique 

subsequent report for each operation. 

The disclosure requirement is included 

in the post-fracture report. The operator 

may post to FracFocus or submit the 

chemical information directly to the 

BLM, and it may withhold trade secret 

information by submitting an affidavit. 

The disclosure requirement only poses 

an incremental burden to the operator in 

states that do not already require 

disclosure to FracFocus. The BLM notes 

that Colorado, Montana, North Dakota, 

Oklahoma, Texas, and Utah, require 

disclosure to FracFocus already and so 

the Federal requirement would not pose 

an incremental burden to those 

operations. 

(a) Applicability of requirement = 100 

percent of operations. 

(b) Cost per requirement = $723. 

Burden includes the operator burden 

($558 per Subsequent Report (SR) 

Sundry) and the BLM burden ($165 per 

SR Sundry). We estimate that the 

operator will require 9 hours at about 

$61.99 per hour to comply with the SR 

Sundry and that the BLM will require 

4.5 hours at about $36.66 per hour to 

review the SR Sundry. The bases for 

these estimates are explained in the 

supporting statement for the Paperwork 

Reduction Act. 

Variance Requests: The operator may 

submit a variance for BLM approval. 

Operators taking advantage of this 

provision will incur an incremental cost. 

Previously, the BLM estimated that it 

might receive variance requests on 10 

percent of the applications, primarily 

because of previously proposed 

requirement to run a CEL on the surface 

casing and the type well provision. 

Since the final rule does not contain 

those provisions, the BLM believes that 

it might receive fewer variance requests. 

However, there is still the potential that 

operators will request a variance (or 

approval) for the storage tank 

requirement or for a CEL on the 

intermediate casing (e.g., the operator 

may request to use a temperature log or 

other test). 

(a) Applicability of requirement = 10 

percent of operations. 

(b) Cost per request = $643. Burden 

includes the operator burden and the 

BLM burden. The compliance cost for 

the operator is estimated to be about 

$496 per application (calculated as 8 

hours at about $61.99 per hour). The 

review cost for the BLM is estimated to 

be about $147 per application 

(calculated as 4 hours at about $36.66 

per hour). 

Benefits Framework 

The potential benefits of the rule are 

significant, but are more challenging to 

monetize than the costs; however, the 

rule will significantly reduce the risks 

associated with hydraulic fracturing 

operations on Federal and Indian lands, 

particularly risks to surface waters and 

usable groundwater. The operational 

requirements of the final rule generally 

conform to industry guidance on 

hydraulic fracturing and state 

regulations. The operational 

requirements should ensure that 

hydraulic fracturing is conducted in a 

manner than minimizes any 

environmental and health risks. 

The use of storage tanks in lieu of pits 

reduces the potential risk to surface and 

groundwater resources. The BLM 

expects that through this rule, since it 

incorporates many of the best practices 

currently used by companies to manage 

recovered fluid, will provide 

environmental benefit and provide the 

best possible avoidance of surface and 

groundwater spills and contamination. 

Pits require careful design, construction 

(including fencing and netting), 

monitoring and reclamation. Rigid steel 

tanks used for recovered fluids are 

typically mounted on truck trailers or 

are transportable by truck. They require 

space on a well pad. However, any leaks 

are readily detectable without special 

equipment. As compared with pits, 

tanks better isolate recovered fluids 

from contamination by surface 

sediments that might increase the costs 

of recycling the fluids. 

The tank requirement also specifies 

that where an operator uses an 

‘‘enclosed’’ tank, the tank may be vented 

unless another Federal, state, or tribal 

law or requirement requires a closedloop system or vapor recovery. Tanks 

that are not enclosed will need to be 

covered, netted or screened to exclude 

wildlife. That is not a new requirement. 

BLM has issued an instructional 

memorandum for authorized officers to 

assure that pits, tanks, and similar 

structures are fully enclosed in netting 

or screens to exclude wildlife. This 

requirement helps prevent accidental 

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16204 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

30The Carlsbad Field Office submitted an Initial 

Report for the major undesirable event, occurring 

on lease NMNM0631. 

deaths of species protected under the 

Migratory Bird Treaty Act or other laws. 

The primary challenge in monetizing 

benefits lies in the quantification of a 

baseline risk associated with specific 

operating practices and in the 

measurement of the change in that risk 

that the BLM can attribute to the rule’s 

requirements. For example, the risk of 

spills associated with the use of pits 

versus the risk of spills associated with 

the use of storage tanks is unknown, 

though it is generally recognized that 

tanks carry less risk onsite. In an initial 

analysis for the proposed rule, we 

attempted to value the reduction in risk, 

but we do not believe that the available 

information represented modern 

hydraulic fracturing operations nor were 

we able to distinguish between the risks 

posed by wells that were hydraulically 

fractured and wells with conventional 

completion techniques. 

Operators are required to notify the 

BLM when undesirable events occur, 

but there are limitations in using the 

BLM data on undesirable events for this 

analysis. Undesirable events may 

include accidents, or accidental spills or 

releases of hydrocarbon fluids, 

produced water, hydraulic fracturing 

flowback fluids, or other substances. 

Undesirable events also include ‘‘frack 

hits,’’ which are unplanned surges of 

pressurized fluids into other wells. 

These events have the potential to 

adversely affect public lands, Indian 

lands, and other important resources. 

There are several limitations in using 

these data. First, the data do not specify 

whether the undesirable events occur in 

conjunction with or as a result of 

hydraulic fracturing operations. In 

addition, the available data cannot be 

readily matched with particular 

provisions in the rule. The data provide 

figures for the incidence of spills, 

accidents, injuries, and other impacts on 

a well, but the pit liner information is 

generally not specified in the incident 

reports for spills or leaks. As such, there 

is difficulty in quantifying the level of 

risk reduction that would be attributed 

to the regulations, even though the 

regulations would most certainly reduce 

risk. 

Although operators are required to 

remediate damage when it occurs, there 

may be uncertainty about the true value 

or extent of any potential damage or 

limitations in connecting an incident to 

an operation. Even if the damage is 

internalized, and as long as the 

compliance costs are less than the 

damage costs, the net benefit to society 

would be less than if the incident was 

avoided, since resources would have 

been unnecessarily dedicated to the 

remediation. 

Damage, in general, is unknown, 

particularly when attempting to 

generalize damage costs which may vary 

by expected magnitude and reversibility 

of effects. Also, the valuation of the 

damage may also take many and highly 

variable forms. For example, an 

undesirable incident occurring during 

hydraulic fracturing might require the 

remediation of surface or subsurface 

areas. The incident might also require 

that the operator shut-in temporarily or 

plug the well before it may produce all 

of the mineral resources. In this case, 

the operator would lose revenue and 

society would not benefit from the 

produced resources. Such would be the 

same for spills. 

The following is an example of an 

event that occurred in 2012 when a 

hydraulic fracturing operation on one 

Federal well affected another Federal 

well. The incident occurred on 

November 20, 2012, in Lea County, New 

Mexico.30 The fracture path of the first 

well intercepted the fracture path of the 

second well, pushing produced fluids 

through the second well and its 

associated equipment such as the 

separator and an open top fiberglass 

tank. The open-top fiberglass tank 

overflowed into an unlined firewall. 

The firewall was over-topped and fluids 

ran into a pasture. The fluids also 

entered a second facility via flow lines 

and over-topped an open fiberglass tank 

to overflow into an unlined containment 

berm. The majority of fluids, 1,220 bbl 

consisting primarily of fracturing fluids, 

were contained within unlined firewalls 

and inside two 210-barrel open-topped 

fiberglass tanks. About 60 bbl of oil ran 

into a pasture near the second well. 

In order to control the event, the 

fracturing job had to be shut in. The 

active wells in the area were also shut 

in. The surface damage included less 

than 0.1 acre of pasture land, and the 

removal and disposal of the material 

inside the two firewalls. Vacuum trucks 

picked up all of the standing fluids. The 

impacted surface material was removed 

for sampling, site delineation, and 

remediation. 

This ‘‘frack hit’’ incident illustrates 

the difficulty in estimating benefits. The 

environmental damage included 

potential surface contamination and 

subsequent remediation efforts, and 

most of the environmental damage 

appears to have been remediated by the 

operator. Aside from the environmental 

damage, there were several economic 

impacts, including the shutting-in of the 

impacted wells for a period of time, 

wellbore damage to the second wells, 

potentially lost fracturing stages, and 

unrecovered resources. 

Since relative risk is unknown, the 

BLM provides a qualitative discussion 

of benefits. Field experience tells us that 

the remediation of a minor incident, 

such as the surface remediation after a 

minor spill, might cost about $15,000 

and range upwards. Remediation efforts 

of larger spills are much more 

complicated and can reach the 

hundreds of thousands of dollars. The 

remediation of a major incident will 

likely be more complex. As with the 

example incident, there were surface, 

possible subsurface impacts to multiple 

wells, and potentially stranded 

resources (from lost fracturing stages of 

permanent plugging of wells). The 

Federal Remediation Technologies 

Roundtable makes a number of case 

studies available on its Web site (though 

none are hydraulic fracturing incidents) 

concerning contamination to aquifers 

where the remediation costs may be $1 

million. 

Discounted Present Value 

There is a time dimension to 

estimates of potential costs and benefits. 

While the incremental costs of the rule 

are likely to occur within a 

comparatively short period of time, the 

incremental benefits may continue into 

the future. The further in the future that 

the benefits and costs are expected to 

occur, the smaller the present value 

associated with the stream of costs and 

benefits. 

For this analysis, we expect that the 

potential incremental costs posed to an 

operation will occur within a short 

timeframe, starting generally with the 

APD submission and ending with the 

subsequent report. As such, we 

generally use undiscounted costs for the 

requirements. However, in order to 

determine the incremental cost of the 

storage tank requirement, we adjusted 

the 5-year data provided by a 

commenter to annualize the costs of 

constructing and operating a pit based 

on the net present value of costs using 

a 7 percent discount rate. 

Uncertainty 

The costs and benefits provided in 

this analysis are estimates and come 

with uncertainty. Generally, the primary 

sources of uncertainty are: 

• Number of hydraulic fracturing 

operations on Federal and Indian lands 

occurring in the future. The economic 

analysis describes the method the BLM 

used to estimate operations that will 

occur in the future. The BLM also 

considers an upper bound estimate 

which should constrain the costs. 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16205 

• Delays and costs associated with 

the CEL on the intermediate casing. 

Sources of uncertainty are: (1) The 

prevalence by which the operator will 

run a log on the intermediate casing as 

a matter of practice; and (2) The ways 

in which operators may run logs on the 

intermediate casing while avoiding 

delays. 

• Storage tank costs. The BLM 

estimated voluntary compliance based 

on the average volume of recovered 

fluids and a number of cost 

assumptions, including the peroperation cost of a pit. In some areas, 

field observations indicate that the use 

of storage tanks is higher than the 

estimated voluntary compliance. As 

such, we believe the compliance costs of 

this requirement are still likely to be 

overestimated. 

• Benefits of specific provisions. The 

BLM is unable to estimate the 

incremental benefits of the rule because 

the BLM is unable to ascribe 

incremental benefits to the particular 

provisions of the rule. Nonetheless, the 

rule’s provisions are generally 

consistent with best management 

practices of the industry at large and of 

several firms within the industry. 

Results: Total Costs of the Rule 

The BLM estimates that the rule will 

impact 2,814 hydraulic fracturing 

operations per year in the near-term on 

Federal and Indian lands. The BLM 

estimates that the incremental cost of 

the rule on Federal and Indian lands 

will be about $26 million per year. 

These estimates are based on 

expectations about the future well 

completions on Federal and Indian 

lands. In order to meet a $100 million 

per year threshold, we estimate that the 

number of hydraulic fracturing 

operations on Federal and Indian lands 

would have to be about 3.83 times 

higher than we anticipate, or over 

10,775 operations per year. 

The estimated per-operation 

compliance costs of about $11,400 

represent about 0.13 to 0.21 percent of 

the cost of drilling a well. The 

compliance costs, shown in Table 6A, 

were developed by dividing the total 

costs of the rule by the number of 

hydraulic fracturing operations 

expected to occur, per year. Because we 

believe that operators would have 

undertaken some of the rule’s 

requirements voluntarily or as a result 

of state requirements, we expect that 

some of the compliance costs will be 

borne by a relatively small number of 

operations. This is particularly the case 

with respect to the requirement to use 

rigid above-ground tanks, which we 

estimate to be less costly than lined pits 

for operations with recovered fluids 

below a certain volume. In those cases 

where fluid volumes exceed a certain 

threshold, we estimate that the 

compliance with the storage tank 

requirement could cost an operator 

$74,400 (representing approximately 0.8 

to 1.4 percent of the cost of drilling a 

well) Through our analysis we estimate 

that this is only a small subset of total 

operations. These operations are those 

where the volumes of recovered fluids 

are expected to be very high and 

typically occur in states (Arkansas, 

Louisiana, Mississippi, Ohio, 

Oklahoma, and Pennsylvania) which 

represent only about 0.8% of estimated 

hydraulic fracturing activities on 

Federal and Indian land (from FY 2010 

to FY 2013). 

The costs of drilling a well may vary 

by reservoir or formation, depth, and 

length, site-specific characteristics, as 

well as operator efficiencies. The Energy 

Information Administration suggests 

costs of about $5.4 million which we 

believe may be a lower bound estimate 

of the costs for drilling a well to be 

completed with hydraulic fracturing. 

The EIA figures were last updated in 

2007, were not specific to horizontal 

wells or hydraulically fractured wells, 

and included costs of drilling 

exploratory or development wells. We 

adjusted the EIA figures to 2015 dollars. 

Meanwhile, horizontal wells drilled in 

the Bakken formation have been 

reported to cost $5.6 million (cited by 

Investopedia from Continental 

Resources in 2010) and, most recently, 

between $7–9 million per well (cited 

from various companies in industry 

trade journal Oil Patch Hotline 2015). 

Small Number of Operations 

As discussed in the Economic 

Analysis, well completions decreased 

on Federal lands from FY 2012 to FY 

2013, but increased steadily on Indian 

lands on an annual basis since FY 2010. 

If the FY 2012 level of activity on 

Federal lands is used as a basis for the 

estimate, the rule could potentially 

impact up to 3,775 hydraulic fracturing 

operations per year on Federal and 

Indian lands at an incremental cost of 

about $45 million per year. 

Many of the rule’s requirements are 

consistent with industry guidance and 

some are required by existing BLM 

regulations and state regulations. 

Accordingly, to the extent that industry 

is already in voluntary compliance, the 

cost of several provisions may be 

overestimated. Where the rule’s 

requirements are consistent with 

industry practice or state regulations, 

there will not be an incremental cost. 

There are two requirements in particular 

that are likely to pose the bulk of the 

estimated costs. 

First, the rule requires the operator to 

run a CEL on the intermediate casing if 

that casing string protects usable water 

and if the operator chooses not to 

cement the casing to the surface. 

Industry guidance suggests that an 

operator may run a cement bond log on 

the intermediate casing to show that the 

casing was cemented to the design. The 

BLM believes that operators will 

generally run logs on the intermediate 

casing, particularly if they plan to 

conduct hydraulic fracturing through a 

production liner that is hung from the 

intermediate casing, and that states or 

the BLM may specify this as a condition 

of approval, even if it is not in 

regulation. Since the BLM does not have 

validating data, the analysis assumes 

that the rule would compel CELs in all 

areas, except those states that require 

them in regulation. As such, the costs 

associated with this requirement are 

likely overstated. 

Second, the rule requires the operator 

to manage recovered fluids in storage 

tanks. Industry guidance suggests that 

operators may use storage tanks or pits 

to manage recovered fluids. Some states 

require the use of tanks by regulation 

and some states have adopted the 

practice as a policy through guidance or 

as a standard condition of approval for 

drilling operations. Our observations of 

field operations indicate that operators 

almost always use storage tanks, which 

indicates that they may be doing so 

voluntarily. The BLM estimated the 

voluntary use of storage tanks in states 

that do not have regulations requiring 

their use. Still, in some areas, our field 

observations indicate that the use of 

storage tanks is higher than the 

estimated voluntary compliance. As 

such, the costs associated with this 

requirement are also likely overstated. 

Cost Breakout According to Federal and 

Tribal Lands 

On Federal lands only, the BLM 

estimates that the final rule would 

impact 2,144 hydraulic fracturing 

operations per year in the near-term 

future and that the rule poses an 

incremental cost of about $22 million 

per year. The rule could potentially 

impact up to 3,105 operations per year 

on Federal lands at an incremental cost 

of about $35 million per year. 

Tables 3A and 3B depict the annual 

incremental costs associated with the 

rule’s requirements, attributed to 

operations on Federal lands within a 

state. It accounts for consistencies 

between a state’s requirements and the 

rule’s requirements. 

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16206 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

On Indian lands, the BLM estimates 

that the final rule would impact 670 

hydraulic fracturing operations per year 

in the near-term future and that the rule 

poses an incremental cost of about $10 

million per year. The estimate accounts 

for the steady increase in activity on 

Indian lands over the past few years. 

Table 4 depicts the annual 

incremental costs associated with the 

rule’s requirements, attributed to 

operations on Indian lands within a 

reservation. The highest total costs are 

associated with operations in the Fort 

Berthold, Uintah and Ouray, and 

Jicarilla Apache reservations, due to the 

volume of activity within those 

reservations. 

TABLE 3A—ESTIMATED ANNUAL INCREMENTAL COSTS ASSOCIATED WITH ACTIVITY ON FEDERAL LANDS

Federal lands, by 

state 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total costs 

ALASKA ............... 9 $5,787 $174 $50,040 $0 $6,507 $579 $63,086 

ALABAMA ............ 1 643 19 5,560 74,400 723 64 81,410 

ARKANSAS .......... 3 1,929 58 16,680 216,727 2,169 193 237,756 

CALIFORNIA ........ 188 120,884 3,627 1,045,280 0 135,924 12,088 1,317,803 

COLORADO ......... 59 37,937 1,138 0 1,242,257 42,657 3,794 1,327,783 

KANSAS ............... 0 0 0 0 0 0 0 0 

LOUISIANA .......... 2 1,286 39 11,120 103,565 1,446 129 117,584 

MISSISSIPPI ........ 6 3,858 116 33,360 148,651 4,338 386 190,709 

MONTANA ........... 1 643 19 5,560 15,178 723 64 22,187 

NORTH DAKOTA 173 111,239 3,337 0 3,204,929 125,079 11,124 3,455,708 

NEW MEXICO ..... 732 470,676 14,120 4,069,920 0 529,236 47,068 5,131,020 

NEVADA .............. 0 0 0 0 0 0 0 0 

OHIO .................... 2 1,286 39 11,120 148,800 1,446 129 162,819 

OKLAHOMA ......... 15 9,645 289 83,400 425,196 10,845 965 530,340 

PENNSYLVANIA .. 12 7,716 231 66,720 829,411 8,676 772 913,526 

SOUTH DAKOTA 4 2,572 77 22,240 0 2,892 257 28,038 

TEXAS ................. 23 14,789 444 63,940 0 16,629 1,479 97,281 

UTAH ................... 579 372,297 11,169 3,219,240 0 418,617 37,230 4,058,553 

WYOMING ........... 335 215,405 6,462 1,862,600 1,919,148 242,205 21,541 4,267,361 

TOTAL .......... 2,144 1,378,592 41,358 10,566,780 8,328,262 1,550,112 137,859 22,002,963 

TABLE 3B—POTENTIAL UPPER BOUND ESTIMATE (USING FY 2012 LEVEL OF ACTIVITY)—ESTIMATED ANNUAL

INCREMENTAL COSTS ASSOCIATED WITH ACTIVITY ON FEDERAL LANDS

Federal lands, by 

state 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total costs 

ALASKA ............... 1 $643 $19 $5,560 $0 $723 $64 $7,010 

ALABAMA ............ 1 643 19 5,560 74,400 723 64 81,410 

ARKANSAS .......... 7 4,501 135 38,920 505,697 5,061 450 554,764 

CALIFORNIA ........ 222 142,746 4,282 1,234,320 0 160,506 14,275 1,556,129 

COLORADO ......... 365 234,695 7,041 0 7,685,148 263,895 23,470 8,214,248 

KANSAS ............... 1 643 19 5,560 3,274 723 64 10,283 

LOUISIANA .......... 4 2,572 77 22,240 207,130 2,892 257 235,168 

MISSISSIPPI ........ 0 0 0 0 0 0 0 0 

MONTANA ........... 15 9,645 289 83,400 227,664 10,845 965 332,808 

NORTH DAKOTA 127 81,661 2,450 0 2,352,751 91,821 8,166 2,536,849 

NEW MEXICO ..... 956 614,708 18,441 5,315,360 0 691,188 61,471 6,701,168 

NEVADA .............. 0 0 0 0 0 0 0 0 

OHIO .................... 3 1,929 58 16,680 223,200 2,169 193 244,229 

OKLAHOMA ......... 15 9,645 289 83,400 425,196 10,845 965 530,340 

PENNSYLVANIA .. 0 0 0 0 0 0 0 0 

SOUTH DAKOTA 5 3,215 96 27,800 0 3,615 322 35,048 

TEXAS ................. 39 25,077 752 108,420 0 28,197 2,508 164,954 

UTAH ................... 517 332,431 9,973 2,874,520 0 373,791 33,243 3,623,958 

WYOMING ........... 827 531,761 15,953 4,598,120 4,737,718 597,921 53,176 10,534,649 

TOTAL .......... 3,105 1,996,515 59,895 14,419,860 16,442,177 2,244,915 199,652 35,363,014 

TABLE 4—ESTIMATED ANNUAL INCREMENTAL COSTS ASSOCIATED WITH ACTIVITY ON TRIBAL LANDS

Reservation or BIA 

agency 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total costs 

ANADARKO ......... 6 $3,858 $116 $33,360 $170,078 $4,338 $386 $212,136 

ARDMORE ........... 0 0 0 0 0 0 0 0 

BLACKFEET ........ 4 2,572 77 22,240 60,710 2,892 257 88,749 

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TABLE 4—ESTIMATED ANNUAL INCREMENTAL COSTS ASSOCIATED WITH ACTIVITY ON TRIBAL LANDS—Continued 

Reservation or BIA 

agency 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total costs 

CHEYENNE & 

ARAPAHO ........ 1 643 19 5,560 28,346 723 64 35,356 

CONCHO ............. 14 9,002 270 77,840 396,850 10,122 900 494,984 

CROW .................. 0 0 0 0 0 0 0 0 

EASTERN NAVAJO ................... 19 12,217 367 105,640 0 13,737 1,222 133,182 

FIVE CIVILIZED 

TRIBES ............. 0 0 0 0 0 0 0 0 

FORT BELKNAP .. 0 0 0 0 0 0 0 0 

FORT BERTHOLD 334 214,762 6,443 0 6,187,550 241,482 21,476 6,671,713 

FORT PECK ........ 0 0 0 0 0 0 0 0 

JICARILLA 

APACHE ........... 93 59,799 1,794 517,080 0 67,239 5,980 651,892 

MUSKUGEE ......... 0 0 0 0 0 0 0 0 

OKMULGEE ......... 2 1,286 39 11,120 56,693 1,446 129 70,712 

PAWNEE .............. 9 5,787 174 50,040 255,118 6,507 579 318,204 

SHAWNEE ........... 0 0 0 0 0 0 0 0 

SHIPROCK .......... 4 2,572 77 22,240 0 2,892 257 28,038 

SOUTHERN UTE, 

BIA .................... 0 0 0 0 0 0 0 0 

TAHLAQUAH ....... 1 643 19 5,560 28,346 723 64 35,356 

TALIHINA ............. 1 643 19 5,560 28,346 723 64 35,356 

TURTLE MOUNTAIN ................. 2 1,286 39 0 37,051 1,446 129 39,950 

UINTAH AND 

QURAY ............. 176 113,168 3,395 978,560 0 127,248 11,317 1,233,688 

UTE MOUNTAIN 

UTE .................. 0 0 0 0 0 0 0 0 

WIND RIVER ....... 4 2,572 77 22,240 22,915 2,892 257 50,954 

TOTAL .......... 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270 

Cost Breakout by Activity 

Tables 5A and 5B show the 

incremental costs by requirement for 

operations on Federal and Indian lands. 

The BLM estimates that the largest 

incremental costs are associated with 

the operational requirements for a CEL 

on certain intermediate casing and 

storage tanks to manage recovered 

fluids. As mentioned previously, the 

BLM does not have specific data about 

the prevalence of voluntary compliance 

with these requirements irrespective of 

the rule. Accordingly, these estimates 

are may be overstated. The BLM 

estimates that the CEL requirement will 

impact a fraction of the operations, but 

could cost operators $12.4 million 

annually (and potentially up to $16.3 

million). The BLM also estimates that 

the incremental annual cost of requiring 

storage tanks (instead of allowing pits) 

could cost operators about $15.6 million 

(and potentially up to $23.7 million). 

Compliance Costs Per-Operation 

The rule would result in compliance 

costs of about $11,400 per hydraulic 

fracturing operation. Average 

compliance costs to meet the 

requirements for a CEL on certain 

intermediate casing and for storage 

tanks represent the bulk of the peroperation compliance costs. The results 

are in Tables 6A and 6B. 

Of the estimated per-operation 

compliance costs, the administrative 

burden represents about $1,450. The 

BLM estimates that the operator will 

assume about $1,118 and the BLM will 

assume $331 of that amount. The 

administrative burden figures are in 

Tables 7A and 7B. 

The review of information associated 

with the application, subsequent report, 

remedial action report (when 

applicable), and variance request (when 

applicable) will pose an additional 

workload to the BLM of about 25,400 

hours per year. That additional burden 

represents about 12.20 full-time 

equivalent (FTE) of workload or, as a 

practical matter, about 13.80 staffed 

positions (takes into account leave and 

holidays). 

TABLE 5A—ESTIMATED ANNUAL INCREMENTAL COSTS, BY REQUIREMENT

Jurisdiction 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total 

costs 

Federal lands ....... 2,144 $1,378,592 $41,358 $10,566,780 $8,328,262 $1,550,112 $137,859 $22,002,963 

Indian lands .......... 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270 

Total .............. 2,814 1,809,402 54,282 12,423,820 15,600,266 2,034,522 180,940 32,103,233 

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TABLE 5B—POTENTIAL UPPER BOUND ESTIMATE (USING FY 2012 LEVEL OF ACTIVITY)—ESTIMATED ANNUAL

INCREMENTAL COSTS, BY REQUIREMENT

Jurisdiction 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total 

costs 

Federal lands ....... 3,105 $1,996,515 $59,895 $14,419,860 $16,442,177 $2,244,915 $199,652 $35,363,014 

Indian lands .......... 670 430,810 12,924 1,857,040 7,272,005 484,410 43,081 10,100,270 

Total .............. 3,775 2,427,325 72,820 16,276,900 23,714,182 2,729,325 242,733 45,463,284 

TABLE 6A—AVERAGE PER-OPERATION COMPLIANCE COSTS, BY REQUIREMENT

Jurisdiction 

Number of 

operations 

per year 

Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

CEL on 

intermediate 

casing 

Storage 

tank 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total 

costs 

Federal lands ....... 2,144 $643 $19 $4,929 $3,884 $723 $64 $10,263 

Indian lands .......... 670 643 19 2,772 10,854 723 64 15,075 

Total .............. 2,814 643 19 4,415 5,544 723 64 11,408 

TABLE 7A—ANNUAL ADMINISTRATIVE BURDEN, BY REQUIREMENT

Party assuming burden Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total 

costs 

Operators ............................................................................. $1,395,744 $41,872 $1,570,212 $139,574 $3,147,403 

BLM ...................................................................................... 413,658 12,410 464,310 41,366 931,744 

Total .............................................................................. 1,809,402 54,282 2,034,522 180,940 4,079,146

TABLE 7B—AVERAGE PER-OPERATION ADMINISTRATIVE BURDEN, BY REQUIREMENT

Party assuming burden Application 

(sundry) 

Remedial 

action 

reporting 

(sundry) 

Post-fracture 

reporting 

(sundry) 

Variance 

requests 

(sundry) 

Total 

costs 

Operators ............................................................................. $496 $15 $558 $50 $1,118 

BLM ...................................................................................... 147 4 165 15 331 

Total .............................................................................. 643 19 723 64 1,450 

Economic Impact Analysis and 

Distributional Assessments 

Energy System Impact Analysis 

Executive Order 13211 requires that 

agencies prepare and submit to the 

Administrator of the Office of 

Information and Regulatory Affairs 

(OIRA), OMB, a Statement of Energy 

Effects for certain actions identified as 

significant energy actions. Section 4(b) 

of Executive Order 13211 defines a 

‘‘significant energy action’’ as ‘‘any 

action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation, including notices of inquiry, 

advance notices of proposed 

rulemaking, and notices of proposed 

rulemaking: (1)(i) That is a significant 

regulatory action under Executive Order 

12866 or any successor order; and (ii) Is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or (2) That is designated by the 

Administrator of OIRA as a significant 

energy action. 

A key consideration is the extent to 

which the costs of the requirements 

might impact investment, production, 

employment, and a number of other 

factors. That is, to what extent, if any, 

would an operator choose to invest in 

other areas, non-Federal and non-Indian 

lands, when faced with the cost 

requirements of the rule. Since the bulk 

of the costs of this rule would apply to 

hydraulic fracturing operations on wells 

that are yet to be drilled (and not on 

existing wells and to refracturing 

operations), operators will be able to 

account for any cost increases up front 

when making investment decisions. 

The BLM believes that the additional 

cost per hydraulic fracturing operation 

is insignificant when compared with the 

drilling costs in recent years, the 

production gains from hydraulically 

fractured well operations, and the net 

incomes of entities within the oil and 

natural gas industries. 

For the average hydraulic fracturing 

operation, the compliance costs 

represent about 0.13 to 0.21 percent of 

the cost of drilling a well. Since the 

estimated compliance costs are not 

substantial when compared with the 

total costs of drilling a well, the BLM 

believes that the rule is unlikely to have 

an effect on the investment decisions of 

firms, and the rule is unlikely to affect 

the supply, distribution, or use of 

energy. 

Employment Impact Analysis 

Executive Order 13563 reaffirms the 

principles established in Executive 

Order 12866, but calls for additional 

consideration of the regulatory impact 

on employment. It states, ‘‘Our 

regulatory system must protect public 

health, welfare, safety, and our 

environment while promoting economic 

growth, innovation, competitiveness, 

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31NAICS codes: 211111—Crude Petroleum and 

Natural Gas Extraction, 211112—Natural Gas Liquid 

Extraction, and 213111—Drilling Oil and Gas Wells. 

and job creation.’’ An analysis of 

employment impacts is a standalone 

analysis and the impacts should not be 

included in the estimation of benefits 

and costs. 

This final rule requires operators, who 

have not already done so, to conduct 

one-time tests on a well or make a onetime installation of a mitigation feature. 

In addition, operators are required to 

perform administrative tasks related to a 

one-time event. 

Compliance with a few of the 

operational requirements is expected to 

pose an additional cost to the operator 

and is likely to shift resources from 

firms in the crude oil and natural gas 

extraction industries (NAICS codes: 

211111—Crude Petroleum and Natural 

Gas Extraction, 211112—Natural Gas 

Liquid Extraction) to firms providing 

support services for drilling oil and gas 

wells (NAICS code: 213111—Drilling 

Oil and Gas Wells). 

Of principal interest is the extent to 

which the financial burden is expected 

to change operators’ investment 

decisions. If the financial burden is not 

significant and all other factors are 

equal, then one would expect operators 

to maintain existing levels of investment 

and employment. The BLM believes that 

the rule would result in an additional 

cost per well hydraulic fracturing 

operation that is small and will not alter 

the investment or employment 

decisions of firms. 

Small Business Impact Analysis 

The Regulatory Flexibility Act as 

amended by the Small Business 

Regulatory Enforcement Fairness Act 

(SBREFA) generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

if a rule would have a significant 

economic impact, either detrimental or 

beneficial, on a substantial number of 

small entities. See 5 U.S.C. 601–612. 

Congress enacted the RFA to ensure that 

Government regulations do not 

unnecessarily or disproportionately 

burden small entities. Small entities 

include small businesses, small 

governmental jurisdictions, and small 

not-for-profit enterprises. 

The BLM reviewed the Small 

Business Administration (SBA) size 

standards for small businesses and the 

number of entities fitting those size 

standards as reported by the U.S. 

Census Bureau in the 2007 Economic 

Census. Using the Economic Census 

data, the BLM concludes that about 99 

percent of the entities operating in the 

relevant sectors 31 are small businesses 

in that they employ fewer than 500 

employees. Also, within these relevant 

sectors, small firms account for 74 

percent of the total value of shipments 

and receipts for services, 86 percent of 

the total cost of supplies, 78 percent of 

the total capital expenditures (excluding 

land and mineral rights), and 67 percent 

of the paid employees (see the 

Economic Analysis). 

Small entities represent the 

overwhelming majority of entities 

operating in the onshore crude oil and 

natural gas extraction industry. As such, 

the rule is likely to affect a significant 

number of small entities. To examine 

the economic impact of the rule on 

small entities, the BLM performed a 

screening analysis for impacts on a 

sample of expected affected small 

entities by comparing compliance costs 

to entity net incomes. 

The firms most likely to be affected by 

the rule are those conducting hydraulic 

fracturing activities on Federal and 

Indian lands. More specifically, the 

firms most impacted are expected to be 

those drilling new wells for hydraulic 

fracture completions. The BLM 

compiled a list of firms that completed 

wells according to AFMSS. The BLM 

expects that these firms are most likely 

to be impacted by the rule. From that 

list, the BLM researched for company 

annual report filings with the Securities 

and Exchange Commission (SEC) to 

determine annual company net incomes 

and employment figures. From the 

original list, the BLM found 55 company 

filings. Of those, 33 were small 

businesses. For the purposes of this 

analysis, the BLM assumes that all 

entities (all lessees and operators) that 

may be affected by this rule are small 

entities, even though that is not actually 

the case. 

Using the net income data for the 

small businesses that filed SEC Form 

10–K, the BLM used the estimated 

compliance costs per hydraulic 

fracturing operation to calculate the 

percent of compliance costs as a portion 

of annual company net incomes for 

2011. The BLM used the absolute values 

of the percentages in the average, so that 

the negative net incomes would not 

negate the positive net incomes, and 

vice versa. Averaging results for the 

small businesses that the BLM 

examined, the average costs of the rule 

are expected to represent about 0.15 

percent of the company net incomes. 

The results of those findings are in 

Table 8. 

TABLE 8—SMALL BUSINESS’ COMPANY NET INCOME AND COMPLIANCE COSTS AS A SHARE OF NET INCOME

Descriptive statistic Company 

net income 

Hydraulic 

fracturing 

operation on 

federal lands 

(%) 

Hydraulic 

fracturing 

operation on 

Indian lands 

(%) 

Hydraulic 

fracturing 

operation 

(without 

distinction) 

(%) 

Average of absolute values ............................................................................. 67,288,696 0.132 0.195 0.147 

Average ............................................................................................................ 27,566,704 0.005 0.008 0.006 

Minimum value ................................................................................................. ¥228,063,000 ¥0.858 ¥1.260 ¥0.954 

Maximum value ................................................................................................ 392,678,000 0.731 1.074 0.813 

The rule deals with hydraulic 

fracturing on all Federal and Indian 

lands (except those excluded by statute). 

Please see the discussion earlier in this 

preamble for the discussion of the need 

for, and objectives of the rule and a 

discussion of the impacts of the rule. 

The BLM received many comments on 

the economic impacts of the 

supplemental proposed rule, as 

discussed elsewhere in this preamble. 

There would be some increased costs 

associated with the enhanced 

recordkeeping requirements and some 

new operational requirements. 

Specifically, there will be increased 

costs for operators to manage recovered 

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fluids in above-ground tanks until they 

have approved plans for disposal of 

produced water pursuant to Onshore 

Order No. 7. Operators that do not 

routinely run a CEL to ensure that the 

producing zone is isolated from usable 

water or that do not routinely run an 

MIT prior to hydraulic fracturing 

operations will face increased costs. 

Submission of hydraulic fracturing 

plans for prior approval, and 

submission of detailed reports after 

hydraulic fracturing operations will be 

new costs, as will the costs of 

submitting chemical information or of 

submitting an affidavit. Maintaining 

access to information on chemicals that 

was withheld from submission may also 

pose a cost. The application, reporting 

and data retention requirements are not 

overly burdensome because they are for 

information readily available to the 

operator or its service contractors. The 

reasons for those requirements and 

responses to comments on each 

requirement are discussed previously in 

this preamble. As shown on Tables 5A, 

5B, 6A, 6B, 7A, 7B, and 8, the BLM 

expects that the costs of compliance 

with this rule would be minor in 

comparison to overall operations costs. 

The BLM has taken steps to reduce 

costs on small entities by not 

promulgating a general requirement to 

run a CEL on surface casings, by 

allowing submission of chemical data 

through FracFocus, by providing for 

submission of a request for approval for 

hydraulic fracturing in a master 

hydraulic fracturing plan, by clarifying 

that isolating and protecting usable 

water means 200 feet of competent 

cement between the fractured zone and 

the usable water zone, by clarifying that 

modeling of fissure propagation is not 

required, and by allowing for both 

operation-specific and state or tribal 

variances. Therefore, the BLM has 

determined that the rule would not have 

a significant economic impact on a 

substantial number of small entities. 

Also, based on the available 

information, the BLM estimates the 

annual effect on the economy of the 

regulatory changes will be less than 

$100 million. This rule will not create 

a major increase in costs or prices for 

consumers, individual industries, 

Federal, state, or local government 

agencies, or geographic regions. In 

addition, this regulation will not have 

any significant adverse effects on 

competition, employment, investment, 

productivity, innovation, or on the 

ability of United States-based 

enterprises to compete with foreignbased enterprises in domestic and 

export markets. 

Executive Order 12866, Regulatory 

Planning and Review 

In accordance with the criteria in 

Executive Order 12866, the Office of 

Management and Budget has 

determined that this rule is a significant 

regulatory action. 

The rule will not have an annual 

effect on the economy of $100 million 

or more or adversely affect in a material 

way the economy, a sector of the 

economy, productivity, competition, 

jobs, the environment, public health or 

safety, or state, local, or tribal 

governments or communities. However, 

the rule may raise novel policy issues 

because of the requirement that 

operators provide to the BLM 

information regarding hydraulic 

fracturing operations that they are not 

currently providing to the BLM. 

This rule would not create 

inconsistencies or otherwise interfere 

with an action taken or planned by 

another agency. This rule would not 

change the relationships of oil and gas 

operations with other agencies. These 

relationships are included in 

agreements and memoranda of 

understanding that would not change 

with this rule. In addition, this rule 

would not materially affect the 

budgetary impact of entitlements, 

grants, loan programs, or the rights and 

obligations of their recipients. Please see 

the discussion of the impacts of the rule 

described earlier in this section of the 

preamble. 

Unfunded Mandates Reform Act 

Under the Unfunded Mandates Act, 

agencies must prepare a written 

statement about benefits and costs prior 

to issuing a proposed or final rule that 

may result in aggregate expenditure by 

state, local, and tribal governments, or 

by the private sector, of $100 million or 

more in any one year. 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for state, local, 

and tribal governments, in the aggregate, 

or to the private sector in any one year. 

Thus, the rule is also not subject to the 

requirements of Sections 202 or 205 of 

the Unfunded Mandates Reform Act 

(UMRA). 

This rule is also not subject to the 

requirements of Section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments; it 

contains no requirements that apply to 

such governments nor does it impose 

obligations upon them. 

Executive Order 12630, Governmental 

Actions and Interference With 

Constitutionally Protected Property 

Rights (Takings) 

Under Executive Order 12630, the 

rule will not have significant takings 

implications. A takings implication 

assessment is not required. This rule 

establishes recordkeeping requirements 

for hydraulic fracturing operations and 

some additional operational 

requirements on Federal and Indian 

lands. All such operations are subject to 

lease terms which expressly require that 

subsequent lease activities be conducted 

in compliance with subsequently 

adopted Federal laws and regulations. 

The rule conforms to the terms of those 

Federal leases and applicable statutes 

and as such the rule is not a 

governmental action capable of 

interfering with constitutionally 

protected property rights. Therefore, the 

rule will not cause a taking of private 

property or require further discussion of 

takings implications under this 

Executive Order. 

Executive Order 13352, Facilitation of 

Cooperative Conservation 

Under Executive Order 13352, the 

BLM has determined that this rule will 

not impede facilitating cooperative 

conservation and takes appropriate 

account of and consider the interests of 

persons with ownership or other legally 

recognized interests in land or other 

natural resources. The rulemaking 

process involved Federal, state, local, 

and tribal governments, private forprofit and nonprofit institutions, other 

nongovernmental entities and 

individuals in the decision-making. The 

process provides that the programs, 

projects, and activities are consistent 

with protecting public health and safety. 

Executive Order 13132, Federalism 

Under Executive Order 13132, this 

rule will not have significant Federalism 

effects. A Federalism assessment is not 

required because the rule will not have 

a substantial direct effect on the states, 

on the relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. The rule will not 

have any effect on any of the items 

listed. The rule affects the relationship 

between operators, lessees, and the 

BLM, but it does not impact states. 

Therefore, under Executive Order 

13132, the BLM has determined that 

this rule will not have sufficient 

Federalism implications to warrant 

preparation of a Federalism Assessment. 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16211 

Executive Order 13175, Consultation 

and Coordination With Indian Tribal 

Governments 

Under Executive Order 13175, the 

President’s memorandum of April 29, 

1994, ‘‘Government-to-Government 

Relations with Native American Tribal 

Governments’’ (59 FR 22951), The 

Department of the Interior Policy on 

Consultation with Indian Tribes (Dec. 1, 

2011), and 512 Departmental Manual 2, 

the BLM evaluated possible effects of 

the rule on federally recognized Indian 

tribes. The BLM approves proposed 

operations on all Indian onshore oil and 

gas leases (except those excluded by 

statute). Therefore, the rule has the 

potential to affect Indian tribes. In 

conformance with the Department’s 

policy on tribal consultation, the Bureau 

of Land Management held four tribal 

consultation meetings to which over 175 

tribal entities were invited. The 

consultations were held in four cities in 

January 2012. 

The purpose of those meetings was to 

solicit initial feedback and preliminary 

comments from the tribes. To date, the 

tribes have expressed concerns about 

the BLM’s Inspection and Enforcement 

program’s ability to enforce the terms of 

this rule; previously plugged and 

abandoned wells being potential 

conduits for contamination of 

groundwater; and the operator having to 

provide documentation that the water 

used for the fracturing operation was 

legally acquired. The BLM considered 

these concerns during the drafting of the 

final rule. 

After publication of the proposed 

rule, the BLM held another series of 

meetings to obtain comments and 

recommendations from tribes and tribal 

organizations. Those meetings were 

held in June 2012 in Utah, New Mexico, 

Oklahoma, and Montana. The BLM also 

engaged in one-on-one consultations as 

requested by several tribes. Some tribal 

representatives were concerned about 

risks to the quality of their vital water 

supplies. Others, though, were more 

concerned with the risk that increased 

compliance costs would drive the 

industry off of Indian lands, and deprive 

the tribes of much-needed revenues and 

economic development. 

After publication of the supplemental 

proposed rule, the BLM again held 

regional meetings with tribes in 

Farmington, New Mexico, and 

Dickinson, North Dakota, in June 2013. 

Representatives from six tribes attended. 

The discussions included a variety of 

tribal-specific and general issues. The 

BLM again offered to follow up with 

one-on-one consultations, and several 

such meetings were held with 

individual tribes. Several tribes, tribal 

members, and associations of tribes 

provided comments on the 

supplemental proposed rule. 

In March 2014, the BLM invited tribes 

to participate in another meeting in 

Denver, Colorado. Representatives from 

seven tribes attended. There was 

significant discussion of issues raised in 

the comments on the supplemental 

proposed rule. The BLM subsequently 

held several consultations with 

individual tribes. 

The BLM understands the importance 

of tribal sovereignty and selfdetermination, and seeks to 

continuously improve its 

communications and government-togovernment relations with tribes. 

The BLM has considered and 

responded to the concerns expressed by 

the tribal representatives both orally and 

in written comments, as described 

previously. In particular, it has made 

changes that will reduce economic 

burdens of compliance for many 

operators. 

Several tribes provided written and 

oral comments critical of the proposed 

rule. Other tribes said that the rules 

violated tribal sovereignty. The final 

rule, however, is not unique. 

Regulations promulgated by the Bureau 

of Indian Affairs render the BLM’s 

operating regulations in 43 CFR part 

3160 applicable to oil and gas leases of 

trust and restricted Indian lands, both 

tribal and individually owned. See 25 

CFR 211.4, 212.4, and 225.4. 

Some tribes insist that those BIA 

regulations are in violation of the 

FLPMA, which they said restricts the 

BLM’s authority to Federal lands. 

Section 301 of the FLPMA, however, 

charges the Director of the BLM to carry 

out functions and duties as the 

Secretary may prescribe with respect to 

the lands and the resources under the 

Secretary’s jurisdiction according to the 

applicable provisions of the FLPMA and 

any other applicable law. 43 U.S.C. 

1731(a). See also 43 U.S.C. 1731(b). The 

Act of March 3,1909 (1909 Act) (at 25 

U.S.C. 396), the Indian Minerals Leasing 

Act (IMLA) (at 25 U.S.C. 396d) and the 

Indian Mineral Development Act 

(IMDA) (at 25 U.S.C. 2107) provide the 

Secretary of the Interior with authority 

to promulgate regulations governing oil 

and gas operations and mineral 

agreements on certain Indian lands. As 

previously cited, the Secretary, through 

delegations in the Departmental Manual 

as reflected in the regulations 

promulgated by the BIA, has assigned to 

the BLM part of the Secretary’s trust 

responsibilities to regulate oil and gas 

operations on those Indian lands. This 

rule concerning Indian lands is 

promulgated pursuant to the 1909 Act, 

the IMLA, and the IMDA, and will be 

implemented by the BLM under those 

authorities, consistent with Section 301 

of the FLPMA. 

Some tribes have asked that the final 

rule exempt Indian lands from its scope. 

Such an exemption would require the 

Secretary of the Interior to conclude, 

among other things, that usable waters 

in Indian lands, and the persons who 

use such waters, are less deserving of 

protection than waters and water users 

on Federal land. The Department of the 

Interior declines to reach that 

conclusion. 

Some tribes have advocated that the 

rule should allow Indian tribes to 

decide individually whether the 

hydraulic fracturing regulations would 

apply on their lands. The BIA’s 

regulations, however, apply to all of the 

BLM’s oil and gas operating regulations 

on Indian lands, and do not allow the 

tribes to pick and select which of the 

BLM’s regulations apply on their lands. 

The tribes, however, report that 

industry representatives have 

threatened not to bid on Indian leases if 

the proposed rules were promulgated. 

The tribes are concerned that a major 

source of revenue and of economic 

development might leave Indian lands 

because of the costs of compliance with 

the rule. The BLM has carefully 

considered the tribes’ comments, along 

with those of the oil and gas industry 

and of concerned citizens and 

governments. The final rule includes 

several changes from the initial 

proposed rules to reduce the costs and 

other burdens of compliance. Examples 

include not requiring a CEL on surface 

casings absent an indication of a 

cementing problem, allowing operators 

to use any one of a class of CELs to 

verify the adequacy of cement casings 

and not requiring the CEL to be 

approved before fracturing operations if 

there is no indication of problems with 

the cementing. The final rule also 

explicitly states that the BLM will 

require isolation of zones that the tribes 

designate for protection from oil and gas 

operations, and will not require 

isolation of zones that tribes have 

exempted from protection. (Note, 

though, that the final rule would not 

exempt an operator from the provisions 

of the SDWA.) Furthermore, the BLM 

could approve a variance from certain 

provisions of the rule applicable to all 

or parts of Indian lands, provided the 

relevant tribal rule meets or exceeds the 

effectiveness of BLM’s rule. Such a 

variance could allow an operator’s 

compliance with a tribe’s standard or 

procedure to be accepted as compliance 

with the revised proposed rule, thus 

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reducing the compliance burdens for 

operators. Such changes should 

significantly reduce compliance costs 

for operators while still assuring 

protection of usable water resources. 

The BLM is aware that the final rule 

could nonetheless result in some higher 

costs for operators on Federal and 

Indian lands, compared with 

compliance costs for hydraulic 

fracturing on non-Federal, non-Indian 

lands in some states with no regulations 

or less protective regulations. 

Regulatory compliance costs, however, 

are only one category in a long list of 

costs that operators compare to 

anticipated revenues when deciding 

whether and how much to bid on a 

Federal or Indian lease. The costs of this 

rule are estimated to be only 0.13 to 0.21 

percent of the cost of drilling a well. It 

has not been the BLM’s experience that 

regulatory compliance costs have 

caused the industry to avoid valuable 

oil and gas resources on Federal and 

Indian lands. 

Executive Order 12988, Civil Justice 

Reform 

Under Executive Order 12988, the 

Office of the Solicitor has determined 

that this rule will not unduly burden the 

judicial system and meets the 

requirements of Sections 3(a) and 3(b)(2) 

of the Order. The Office of the Solicitor 

has reviewed the rule to eliminate 

drafting errors and ambiguity. It has 

been written to minimize litigation, to 

provide clear legal standards for affected 

conduct rather than general standards, 

and to promote simplification and avoid 

unnecessary burdens. 

Paperwork Reduction Act 

The Paperwork Reduction Act (44 

U.S.C. 3501–3521) provides that an 

agency may not conduct or sponsor, and 

a person is not required to respond to, 

a ‘‘collection of information,’’ unless it 

displays a currently valid OMB control 

number. Collections of information 

include requests and requirements that 

an individual, partnership, or 

corporation obtain information, and 

report it to a Federal agency (44 U.S.C. 

3502(3); 5 CFR 1320.3(c) and (k). 

The BLM included a request for 

approval of a collection of information 

in both the proposed rule and the 

supplemental proposed rule. OMB 

approved the collection for the final rule 

under control number 1004–0203. 

Compliance with this collection of 

information will be required to obtain or 

retain a benefit for the operators of 

Federal and Indian (except on the Osage 

Reservation, the Crow Reservation, and 

certain other areas) onshore oil and gas 

leases, units, or communitization 

agreements that include Federal leases. 

After the effective date of the final rule, 

the BLM plans to request that OMB 

merge control number 1004–0203 with 

control number 1004–0137, ‘‘Onshore 

Oil and Gas Operations,’’ (expiration 

date: January 31, 2018). 

The following activities comprise the 

information collection for the final rule. 

Request for Prior Approval 

• The final rule removes the 

distinction in existing 43 CFR 3162.3– 

2 between ‘‘routine’’ and ‘‘non-routine’’ 

fracturing jobs, and requires in section 

3162.3–3(a) that operators propose and 

seek prior BLM approval for all 

hydraulic fracturing jobs except for 

three instances in which a well is 

drilled shortly before or after the 

effective date of the rule, and is 

hydraulically fractured within 90 days 

after the effective date of the rule. 

However, all other applicable provisions 

of the rule must be adhered to, 

including 3162.3–3(e), relating to 

monitoring and verification of 

cementing operations prior to hydraulic 

fracturing. 

Section 3162.3–3(c) provides that a 

request to commence hydraulic 

fracturing may be submitted either on 

Form 3160–5 as a ‘‘Notice of Intent 

(NOI) Sundry’’ or as part of Form 3160– 

3, Application for Permit to Drill (APD), 

both of which are authorized by control 

number 1004–0137. The BLM will use 

the following-described information to 

determine whether or not to grant prior 

approval for hydraulic fracturing jobs. 

Section 3162.3–3(d)(6) lists two 

requirements that apply only if an 

operator requests prior approval for 

hydraulic fracturing in an NOI after 

drilling and completing a well. The first 

requirement (at paragraph (d)(6)(i)) is a 

surface use plan of operations if the 

hydraulic fracturing operation would 

include surface disturbance. The second 

requirement (at paragraph (d)(6)(ii)) is 

documentation that adequate cementing 

was achieved for all casing strings 

designed to isolate usable water zones. 

These requirements are included in the 

collection activity labeled ‘‘Request for 

Prior Approval of Hydraulic Fracturing 

Job Using a Notice of Intent Sundry Plus 

a Surface Use Plan of Operations Plus 

Documentation of Adequate 

Cementing.’’ 

While the well completion report 

(Form 3160–4) that is approved under 

control number 1004–0137 requires 

some information about cementing, the 

second requirement in paragraph 

(d)(6)(ii) is not duplicative. The wellcompletion report requires the operator 

to disclose the number of sacks and type 

of cement, the slurry volume, the 

cement trop, and any cement squeeze 

information. The information we are 

requiring in paragraph (d)(6)(ii) is actual 

monitoring information from when the 

cementing operations took place, for 

example, pump pressures, cement 

density, and observations during the 

cement job. We anticipate that typically, 

an operator will comply with paragraph 

(d)(6)(ii) by providing us with 

information recorded on a service 

company’s ‘‘job ticket.’’ 

Section 3162.3–3(e)(1) lists two 

requirements that apply only if an 

operator requests prior approval for 

hydraulic fracturing in an Application 

for Permit to Drill before drilling and 

completing a well. This provision 

requires operators to submit a cement 

operation monitoring report to the BLM 

before commencing hydraulic fracturing 

operations. The required elements of a 

cement operation monitoring report are 

(1) The flow rate, density, and pump 

pressure during pre-fracturing 

cementing operations on any casing 

used to isolate usable water zones; and 

(2) A determination of adequate cement 

for all casing strings that are used to 

isolate usable water zones. These 

requirements are included in the 

collection activity labeled, ‘‘Request for 

Prior Approval of Hydraulic Fracturing 

Job Using an Application for Permit to 

Drill Plus a Cement Operation 

Monitoring Report.’’ 

Unlike the supplemental proposed 

rule, the final rule does not require the 

operator to identify a ‘‘type well’’ as part 

of a request for prior approval for a 

group of wells. Instead, section 3162.3– 

3(c)(3) of the final rule provides for the 

submission of an MHFP. The differences 

between the ‘‘type well’’ requirement 

and the requirement for an MHFP are 

described in the preamble discussion of 

43 CFR 3160.0–5 (‘‘Definitions’’). This 

discussion clarifies that the MHFP for a 

group of wells is only for initial 

planning purposes and that operators 

must submit all required information for 

each well and get approval for each well 

before drilling. 

Remedial Action Plan 

Section 3162.3–3(e)(3) requires an 

operator to notify the BLM within 24 

hours of discovering inadequate cement 

on any casing used to isolate usable 

water and submit an NOI to the BLM 

requesting approval of a plan to perform 

remedial action. The BLM will use this 

collection activity to determine the 

adequacy of the proposed remedial 

action. At least 72 hours before starting 

hydraulic fracturing operations, 

operators must submit a subsequent 

report for the remedial action, which 

would include a signed certification that 

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the operator corrected the inadequate 

cement job along with the results from 

the CEL or other method showing that 

there is adequate cement. 

Subsequent Report 

Section 3162.3–3(i) lists information 

that must be provided to the BLM 

within 30 days after the completion of 

the last stage of hydraulic fracturing 

operations. We have revised the 

information that is required. The 

information is required for each well, 

even if the authorized officer approved 

fracturing of a group of wells. 

The final rule lists the following 

requirements for a subsequent report: 

(1) The true vertical depth of the well, 

total water volume used, and a 

description of the base fluid and each 

additive in the hydraulic fracturing 

fluid, including the trade name, 

supplier, purpose, ingredients, 

Chemical Abstract Service Number 

(CAS), maximum ingredient 

concentration in additive (percent by 

mass), and maximum ingredient 

concentration in hydraulic fracturing 

fluid (percent by mass). This 

information must be submitted to the 

authorized officer through FracFocus, 

another BLM-designated database, or in 

a subsequent report. If information is 

submitted through FracFocus or another 

BLM-designated database, the operator 

must specify that the information is for 

a Federal or an Indian well, certify that 

the information is correct, and certify 

compliance with applicable law; 

(2) The actual source(s) and 

location(s) of the water used in the 

hydraulic fracturing fluid; 

(3) The maximum surface pressure 

and rate at the end of each stage of the 

hydraulic fracturing operation and the 

actual flush volume; 

(4) The actual, estimated, or 

calculated fracture length, height and 

direction; 

(5) The actual measured depth of 

perforations or the open-hole interval; 

(6) The total volume of fluid 

recovered between the completion of 

the last stage of hydraulic fracturing 

operations and when the operator starts 

to report water produced from the well 

to ONRR. If the operator has not begun 

to report produced water to ONRR when 

the subsequent report is submitted, the 

operator must submit a supplemental 

subsequent report to the authorized 

officer documenting the total volume of 

recovered fluid; 

(7) The following information 

concerning the handling of fluids 

recovered covering the period between 

the commencement of hydraulic 

fracturing and the implementation of 

the approved plan for the disposal of 

produced water under BLM regulations 

(currently in Onshore Order 7): 

(i) The methods of handling the 

recovered fluids, including, but not 

limited to, transfer pipes and tankers, 

holding pond use, re-use for other 

stimulation activities, or injection; and 

(ii) The disposal method of the 

recovered fluids, including, but not 

limited to, the percent injected, the 

percent stored at an off-lease disposal 

facility, and the percent recycled; 

(8) A certification signed by the 

operator that: 

(i) The operator complied with the 

requirements in 43 CFR 3162.3–3(b), (e), 

(f), (g), and (h); 

(ii) For Federal lands, the hydraulic 

fracturing fluid constituents, once they 

arrived on the lease, complied with all 

applicable permitting and notice 

requirements as well as all applicable 

Federal, state, and local laws, rules, and 

regulations; and 

(iii) For Indian lands, the hydraulic 

fracturing fluid constituents, once they 

arrived on the lease, complied with all 

applicable permitting and notice 

requirements as well as all applicable 

Federal and tribal laws, rules, and 

regulations; 

(9) The operator must submit the 

result of the mechanical integrity test as 

required by 43 CFR 3162.3–3(f); and 

(10) The BLM may require the 

operator to provide documentation 

substantiating any of the information 

listed previously. 

The information required in 

paragraphs (2) though (10), previously, 

must be submitted to the authorized 

officer in a subsequent report. This 

information will enable the BLM to have 

a complete record of the hydraulic 

fracturing job. 

Affidavit in Support of Claim of 

Confidentiality 

Section 3162.3–3(j) describes how an 

operator, or the operator and the owner 

of the information, may support a claim 

to be exempt from public disclosure of 

information otherwise required in the 

subsequent report. If required 

information is withheld, the regulation 

requires submission with the 

subsequent report of an affidavit that: 

• Identifies the owner of the withheld 

information and provides the name, 

address and contact information for an 

authorized representative of the owner; 

• Identifies the Federal statute or 

regulation that would prohibit the BLM 

from publicly disclosing the information 

if it were in the BLM’s possession; 

• Affirms that the operator has been 

provided the withheld information from 

the owner of the information and is 

maintaining records of the withheld 

information, or that the operator has 

access and will maintain access to the 

information held by the owner of the 

information; 

• Affirms that the information is not 

publicly available; 

• Affirms that the information is not 

required to be publicly disclosed under 

any applicable local, state, or Federal 

law (on Federal lands), or tribal or 

Federal law (on Indian lands); 

• Affirms that the owner of the 

information is in actual competition and 

identifies competitors or others that 

could use the withheld information to 

cause the owner substantial competitive 

harm; 

• Affirms that the release of the 

information would likely cause 

substantial competitive harm to the 

owner and provides the factual basis for 

that affirmation; and 

• Affirms that the information is not 

readily apparent through reverse 

engineering with publicly available 

information. 

In addition, if the operator relies upon 

information from third parties, such as 

the owner of the withheld information, 

to make the previous affirmations, the 

operator must provide a written 

affidavit from the third party that sets 

forth the relied-upon information. The 

BLM will use the information to 

determine whether to grant an 

exemption from public disclosure of 

information that otherwise would be 

required in a subsequent report. 

Section 3162.3–3(j)(5) requires the 

operator to maintain records of any 

withheld information until the later of 

the BLM’s approval of a final 

abandonment notice, or 6 years from the 

completion of hydraulic fracturing 

operations on Indian lands, or 7 years 

from the completion of hydraulic 

fracturing operations on Federal lands, 

consistent with applicable law. Any 

subsequent operator will be responsible 

for maintaining access to records of any 

withheld information during its 

operation of the well. The operator will 

be deemed to be maintaining the records 

if it can promptly provide the complete 

and accurate information to the BLM, 

even if the information is in the custody 

of its owner. This provision enables the 

BLM to have access to records of 

injected chemicals during the life of the 

well, while protecting trade secrets. 

Section 3162.3–3(j)(6) provides that if 

any of the chemical identity information 

is withheld, the operator must provide 

the generic chemical name in the 

subsequent report. 

Variance Request 

Section 3162.3–3(k) provides that a 

decision on a variance request is not 

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16214 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

subject to administrative appeal either 

to the State Director or under 43 CFR 

part 4. 

Necessity/Avoidance of Unnecessary 

Duplication 

The Paperwork Reduction Act 

requires each Federal agency to certify 

that its collections of information are 

necessary for the proper performance of 

agency functions, and are not 

unnecessarily duplicative of 

information otherwise reasonably 

accessible to the agency. 43 U.S.C. 

3506(c)(3)(A) and (B). We received 

many comments on the proposed rule 

with respect to this standard, and we 

responded to them in the supplemental 

proposed rule. In addition, we received 

the following comments on the 

supplemental proposed rule with 

respect to this standard. 

Comments: Numerous commenters 

said that in states where there is already 

a regulatory process for hydraulic 

fracturing, an operator should be 

allowed to submit the same information 

to the BLM as it does to the state. 

Response: We made no changes as a 

result of these comments because the 

rule already addresses the expressed 

concerns. Section 3162.3–3(d) allows 

information submitted in accordance 

with state or tribal law to be submitted 

to the BLM if the information meets the 

standards of this rule. Section 3162.3– 

3(k)) allows the BLM to issue a 

statewide or regional variance to use 

state or tribal regulations and processes 

for permitting hydraulic fracturing 

operations if they meet or exceed the 

objectives of this rule. 

Comment: One commenter requested 

that the BLM clarify the following 

statement in section 3162.3–3(d): If 

information submitted in accordance 

with states (on Federal lands) or tribal 

(on Indian lands) laws or regulations 

meets the standards prescribed by the 

BLM, such information may be 

submitted to the BLM as part of the 

Sundry Notice. 

Response: We did not revise the rule 

in response to this comment. The 

statement in section 3162.3–3(d) 

provides clearly that if the information 

submitted to states or tribes meets the 

standards in this section, the operator 

does not need to generate any 

information. Operators may submit the 

information that was generated to meet 

the state or tribal requirements to the 

BLM. 

Comments: Some commenters on the 

supplemental proposed rule questioned 

the necessity of collecting information 

in a subsequent report within 30 days 

after the completion of the last stage of 

hydraulic fracturing operations under 

section 3162.3–3(i). They stated that 

much of the information is required 

either in the NOI or in the well 

completion report (Form 3160–4) that is 

required by 43 CFR 3162.4–1(b). 

Response: We disagree with 

comments claiming duplication 

between the NOI and the subsequent 

report. The information in the NOI 

allows the BLM to analyze the proposed 

operations to ensure that there will not 

be any unnecessary or undue 

degradation of public lands or breach of 

trust on Indian lands. The information 

also enables the BLM to develop any 

necessary mitigation to protect 

resources. In contrast, the information 

in the subsequent report allows the BLM 

to determine whether or not operations 

were conducted as designed and 

authorized. Some information, such as 

the results of the MIT and the cement 

operations monitoring report, are not 

included in the NOI, and can only be 

submitted after the operations are 

complete. 

We did revise section 3162.3–3(i)(9) 

(paragraph (i)(8) of the supplemental 

proposed rule) in response to comments 

saying that the proposed requirement to 

submit well logs and records of 

adequate cement duplicates a 

requirement in the well completion 

report. However, we made no changes to 

section 3162.3–3(i) in response to other 

comments saying that the information 

required in the subsequent report 

duplicates information that is required 

in the well completion report. Examples 

of data that are required in the 

subsequent report, but not in the well 

completion report, include the cement 

operations monitoring report, the results 

of the MIT, and the operator 

certification that it complied with the 

paragraphs in the rule that assure 

wellbore integrity was maintained prior 

to and throughout the hydraulic 

fracturing operation. 

Comment: A commenter 

recommended that all cementing 

requirements be eliminated from the 

rule because cementing operations are 

part of drilling operations and 

information is already submitted to state 

regulatory agencies for such operations. 

The commenter also asserted that 

cementing operations have little to do 

with hydraulic fracturing. 

Response: We did not revise any 

provision in response to this comment. 

While cementing information is already 

submitted to state regulatory agencies 

and the BLM, this rule expands on the 

requirements by including cement 

monitoring, cement remediation, and 

cement evaluation. Moreover, the 

cementing information that is required 

is related to protection of usable water 

from hydraulic fracturing operations. 

Comments: Some commenters stated 

that information regarding the water 

source that is required in section 

3162.3–3(d)(3) would have already been 

provided as part of an APD. 

Response: We did not revise the rule 

in response to this comment. While 

section III.D.4.e of Onshore Order 1 

requires the operator to identify the 

location and type of water supply to be 

used during the drilling operations in 

the APD, this may or may not be the 

same as the water supply for hydraulic 

fracturing operations. Since the water 

supply may be different, this 

information must be included in the 

application for hydraulic fracturing. 

Practical Utility 

The Paperwork Reduction Act 

requires that each Federal agency certify 

that each collection of information has 

practical utility. The term ‘‘practical 

utility’’ means the ability of an agency 

to use information, particularly the 

capability to process such information 

in a timely and useful fashion. 44 U.S.C 

3502(11) and 3506(c)(3)(A). 

Comments: Commenters expressed 

various concerns with the requirement 

in section 3162.3–3(d)(3) to provide 

information concerning the water source 

and location of water supply. Some 

stated that they were unsure how we 

would use the information. Others 

stated that the water source could 

change and filing a Sundry Notice for 

the BLM to approve the change is 

burdensome. 

Response: We did not revise the final 

rule in response to these comments. We 

require information about the proposed 

source of the water in order to conduct 

and document an environmental effects 

analysis that takes a hard look at the 

impacts of its Federal action and meets 

the requirements of NEPA. The BLM has 

always required operators to file a 

Sundry Notice for changes to the 

approved permit—whether it is an APD 

or an NOI for hydraulic fracturing. 

Clarity 

The Paperwork Reduction Act 

requires each Federal agency to certify 

that each collection of information is 

written using plain, coherent, and 

unambiguous terminology and is 

understandable to those who are to 

respond. 44 U.S.C. 3506(c)(3)(D). 

Comments: Some commenters 

recommended restructuring of sections 

3162.3–3(d)(3) and 3162.3–3(d)(4) of the 

supplemental proposed rule (pertaining 

to the NOI). They stated that 

restructuring these provisions would 

add clarity to the requirements. 

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Response: We revised sections 

3162.3–3(d)(3) and 3162.3–3(d)(4) as 

suggested in these comments. Section 

3162.3–3(d)(3) now requires information 

concerning the source and location of 

the water supply. The requirement for 

the measured depth of the proposed 

perforated or open-hole interval is 

moved to section 3162.3–3(d)(4)(v). The 

information regarding the proposed 

perforated interval is now a distinct 

requirement, and this information 

relates more closely with the other 

information required by section 3162.3– 

3(d)(4). 

Consistency With Existing Reporting 

and Recordkeeping Practices 

The Paperwork Reduction Act 

requires each Federal agency to certify 

that its collections of information are to 

be implemented in ways consistent and 

compatible, to the maximum extent 

practicable, with the existing reporting 

and recordkeeping practices of those 

who are to respond. 44 U.S.C. 

3506(c)(3)(E). We received comments on 

the proposal to allow some of the 

information in a subsequent report to be 

submitted through FracFocus or another 

BLM-designated database. 

Comments: Some commenters 

supported the provision (section 

3162.3–3(i)) that allows some of the 

information in a subsequent report to be 

submitted through FracFocus or another 

BLM-designated database. They stated 

that provision would reduce duplication 

of efforts for the operators. They also 

supported the provision that allows 

operators in states that require 

disclosure on FracFocus to meet both 

the state and the BLM requirements 

through a single submission to 

FracFocus. 

Some commenters suggested that 

additional information, such as the 

APD, status, compliance, volume of 

fluid recovered, and complaint process, 

should be reported through the 

FracFocus submission. 

Other commenters were critical of 

FracFocus as not being user-friendly 

and for not allowing re-publication or 

linking with other databases. Some 

commenters were critical of FracFocus 

because of the unknown future 

condition and long-term reliability of 

this organization in hosting and 

retaining the data. A few commenters 

expressed concern about future funding, 

access, and data backup issues of 

FracFocus. Other commenters suggested 

that the disclosure registry should be 

searchable across forms and allow for 

meaningful cross-tabulation of search 

results. One of the commenters 

specified that each of the disclosure 

submissions should have a date stamp 

showing the actual date of submission 

to the database and validate/reject the 

correct/incorrect CAS Registry Numbers 

of the disclosed chemicals/ingredients 

when submitted. Another commenter 

suggested that the BLM should develop 

a public disclosure platform tailored to 

the agency’s needs. 

Some commenters expressed concern 

that the ownership of the data on 

FracFocus and the applicability of 

public disclosure laws, such as FOIA 

are unknown. A commenter suggested 

that the BLM adopt a procedure used in 

Texas that requires operators to submit 

to the state commission a copy of the 

information that they upload to 

FracFocus. 

Some commenters argued that using 

FracFocus would violate an executive 

order requiring government information 

to be available to the public in open, 

machine-readable formats, and the 

implementing guidance from the Office 

of Management and Budget. See 

Executive Order 13642, 78 FR 93 (2013), 

and Memorandum for the Heads of 

Executive Departments and Agencies, 

M–13–13 (OMB 2013). That order 

provides, in pertinent part that the 

policy of the Executive Branch is that 

modernized Government information 

resources must be open and machine 

readable. The order is subject to several 

conditions, including available 

appropriations. 

A commenter was concerned that 

using FracFocus could cause a conflict 

of interest because the GWPC is a trade 

association for oil and gas. 

A commenter argued that using 

FracFocus would fail to meet minimum 

standards for managing government 

records. 

A commenter raised an issue of 

implementation and enforcement—that 

because FracFocus does not show the 

date that information is uploaded, it 

will be difficult for the BLM to know if 

the information was submitted within 

the time required by the rule. 

Response: The BLM did not make any 

changes to the rule in response to these 

comments. The responses that are 

summarized here are discussed in detail 

earlier in the preamble discussion of 

section 3162.3–3(i). 

Under this final rule, submission of 

the required information through 

FracFocus is optional; an operator may 

instead submit it directly to BLM. The 

BLM’s intent, however, is to reduce the 

paperwork burden on operators by 

allowing them to submit information 

through FracFocus, if they so choose. 

Thus, in states that require submission 

on FracFocus, there would be no 

additional burden of complying with 

this requirement of the rule. If an 

operator submits the information 

directly to the BLM, the BLM will 

upload the information to FracFocus, 

and retain a copy in its files. 

The BLM did not adopt suggestions to 

allow additional information to be 

reported through the FracFocus 

submission because FracFocus is 

limited to chemical disclosures. 

The GWPC has upgraded the 

FracFocus database to enhance its 

functionality for the public, state 

regulatory agencies and industry users. 

As mentioned earlier under New 

Requirements, GWPC and IOGCC, joint 

venture partners in the FracFocus 

initiative, announced the release of 

several improvements to FracFocus’ 

system functionality. The new features 

are designed to reduce the number of 

human errors in disclosures, expand the 

public’s ability to search records, 

provide public extraction of data in a 

‘‘machine readable’’ format, update 

educational information on chemical 

use, environmental impacts from oil and 

gas production, and potential 

environmental impacts. The new selfchecking features in the system will 

help companies detect and correct 

possible errors before disclosures are 

submitted. This feature will detect 

errors verifying that CAS numbers meet 

the proper format. GWPC recently met 

with the BLM and confirmed the 

following updates to FracFocus: 

(a) Validation of the CAS number; 

(b) Reduction of errors by taking 

measures, such as a water volume alert 

if the operators input exceedingly high 

numbers (>15 million gallons) in error, 

multiple disclosures with the same API 

numbers, etc.; 

(c) Validation checks of the maximum 

ingredient concentration, using two 

checks/alerts when the sum exceeds 3% 

and 10%; 

(d) Improved public search 

capabilities with faster response times 

when filtering search results; 

(e) Updated record retention and 

amendment aspects to keep a backup 

copy of every disclosure submitted to 

FracFocus; 

(f) Adopted established record 

management standards to meet proper 

data quality objectives; 

(g) Notify the BLM through a group 

email box when an operator uploads the 

chemical disclosure data for a well; 

(h) Include a link to a downloadable 

file containing the data in a machinereadable format; and 

(i) Provide a date stamp when 

chemical disclosure data is uploaded 

from the BLM operations. 

These updates are addressed in the 

most recent iteration of FracFocus. 

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16216 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

The agreement would also require 

GWPC to include the BLM as a member 

of the Full and Technical Committees to 

engage in updates and developments to 

FracFocus. 

The BLM expects that these 

requirements will yield further progress 

and improvement of the FracFocus site 

to meet the requirements of the rule by 

providing an effective chemical 

disclosure registry for the hydraulic 

fracture fluids. 

The Federal FOIA does not apply to 

FracFocus, because it is operated by the 

GWPC, which is not an agency of the 

Federal Government. However, 

information on FracFocus concerning 

Federal or tribal wells is public 

information because FracFocus is a 

public Web site and there would be no 

need for the costs of delays associated 

with awaiting a response to a FOIA 

request. The public can access that 

information for themselves. 

Executive Order 13642 does not 

prohibit the BLM from allowing 

operators to submit information through 

FracFocus. We believe that FracFocus is 

the quickest, most cost-effective way to 

make the information public. Working 

with FracFocus to meet the policy goals 

of the Executive Order, including 

machine-readable formats, will be more 

prompt and will use taxpayer dollars 

more efficiently than would the BLM 

creating and managing its own database 

solely for chemical disclosures. 

The use of FracFocus does not 

constitute a conflict of interest. The 

members of GWPC are the states 

agencies (www.gwpc.org/state-agencies) 

that protect and regulate groundwater 

resources. They do not have a conflict 

of interest in operating FracFocus to 

serve as a way for operators to submit 

data to the BLM, or in making that 

information available to the public. 

The use of FracFocus does not 

conflict with requirements for records 

management. FracFocus will not be the 

official repository of the chemical 

information required by the rule. 

Whether an operator submits 

information to the BLM directly or 

through FracFocus, the BLM will 

maintain access to all the relevant 

information. The information will also 

be available on FracFocus for the benefit 

of the public and state and tribal 

agencies. 

The BLM will closely monitor 

FracFocus to ensure that operators 

submit information in a timely manner 

consistent with these regulations. 

Operators also have an incentive to 

assure that the BLM has received the 

required information within the 

deadlines. The BLM will be working 

with the GWPC to improve the ability of 

FracFocus to meet the BLM’s needs and 

of operators on Federal or tribal lands. 

Estimates of Burdens 

The following table shows the 

estimated annual paperwork burdens 

associated with this rule. 

ESTIMATES OF HOUR BURDENS

A. B. C. 

D. 

(column B × 

column C) 

Total hours Type of 

response 

Number of 

responses 

Hours per 

response 

Request for Prior Approval of Hydraulic Fracturing Job Using an Application for Permit to Drill 

Plus a Cement Operation Monitoring Report 43 CFR 3162.3–3(c)(1), (d), (e)(1), and (e)(2) 

Form 3160–3 ............................................................................................................................ 2,614 8 20,912 

Request for Prior Approval of Hydraulic Fracturing Job Using a Notice of Intent Sundry Plus 

a Surface Use Plan of Operations Plus Documentation of Adequate Cementing 43 CFR 

3162.3–3(c)(2), (c)(3), (d), and (e). Form 3160–5 ................................................................... 200 8 1,600

Sundry Notices and Reports on Wells/Hydraulic Fracturing/Request for Approval of Remedial 

Plan 43 CFR 3162.3–3(e)(3) Form 3160–5 ............................................................................. 84 8 672 

Sundry Notices and Reports on Wells/Hydraulic Fracturing/Subsequent Report Sundry Notice 

43 CFR 3162.3–3(g) and (i) Form 3160–5 .............................................................................. 2,814 8 22,512 

Affidavit in Support of Claim of Confidentiality 43 CFR 3162.3–3(j) ........................................... 2,814 1 2,814 

Sundry Notices and Reports on Wells/Hydraulic Fracturing/Variance Request 43 CFR 

3162.3–3 Form 3160–5 ............................................................................................................ 281 8 2,248 

Totals .................................................................................................................................... 8,807 ........................ 50,758 

No capital and start-up costs are 

involved with this information 

collection—respondents are not 

required to purchase additional 

computer hardware or software to 

comply with these information 

collection requirements. The Fiscal Year 

2015 appropriations law (Pub. L. 113– 

203) directs the BLM to charge a $6,500 

processing fee for Form 3160–3, 

Application for Permit to Drill or ReEnter. We estimate that 5,000 of these 

applications are filed annually under 

control number 1004–0137, and another 

2,614 will be filed under control 

number 1004–0203. The estimated nonhour cost burden is $32,500,000 under 

control number 1004–0137, and 

$16,991,000 under 1004–0203. The total 

estimated non-hour cost burden is 

$49,491,000. 

National Environmental Policy Act 

The BLM has prepared an 

environmental assessment (EA) that 

concludes that this rule will not 

constitute a major Federal action that 

may result in a significant effect on the 

human environment under section 

102(2)(C) of the National Environmental 

Policy Act (NEPA), 42 U.S.C. 4332(2)(C). 

The EA, the Finding of No Significant 

Impact, and the Decision Record are 

available for review and on file in the 

BLM Administrative Record at the 

address specified in the ADDRESSES

section. 

Data Quality Act 

In developing this rule, the BLM did 

not conduct or use a study, experiment, 

or survey requiring peer review under 

the Data Quality Act (Pub. L. 106–554). 

Executive Order 13211, Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Under Executive Order 13211, 

agencies are required to prepare and 

submit to OMB a Statement of Energy 

Effects for significant energy actions. 

This Statement is to include a detailed 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16217 

statement of ‘‘any adverse effects of 

energy supply, distribution, or use 

(including a shortfall in supply, price 

increases, and increase use of foreign 

supplies)’’ for the action and reasonable 

alternatives and their effects. 

Section 4(b) of Executive Order 13211 

defines a ‘‘significant energy action’’ as 

‘‘any action by an agency (normally 

published in the Federal Register) that 

promulgates or is expected to lead to the 

promulgation of a final rule or 

regulation, including notices of inquiry, 

advance notices of proposed 

rulemaking, and notices of proposed 

rulemaking: (1)(i) That is a significant 

regulatory action under Executive Order 

12866 or any successor order, and (ii) is 

likely to have a significant adverse effect 

on the supply, distribution, or use of 

energy; or 2) That is designated by the 

Administrator of OIRA as a significant 

energy action.’’ 

The BLM believes that the additional 

cost per hydraulic fracturing operation 

is insignificant when compared with the 

drilling costs in recent years, the 

production gains from hydraulically 

fractured well operations, and the net 

incomes of entities within the oil and 

natural gas industries. For the average 

hydraulic fracturing operation, the 

compliance costs represent about 0.13 to 

0.21 percent of the cost of drilling a 

well. 

Since the estimated compliance costs 

are not substantial when compared with 

the total costs of drilling a well, the 

BLM believes that the rule is unlikely to 

have an effect on the investment 

decisions of firms, and the rule is 

unlikely to affect the supply, 

distribution, or use of energy. As such, 

the rule is not a ‘‘significant energy 

action’’ as defined in Executive Order 

13211. 

Authors 

The principal authors of this rule are: 

Bryce Barlan, Program Analysis Officer, 

BLM Washington Office; James 

Tichenor, Economist, BLM Washington 

Office; Gerald Dickinson, Petroleum 

Engineer, BLM Rawlins Field Office; 

John Ajak, Petroleum Engineer, 

Washington Office; John Pecor, 

Petroleum Engineer, BLM Tre Rios Field 

Office; Rich Estabrook, Petroleum 

Engineer, BLM Washington Office; 

Rosemary Herrell, Senior Policy 

Analyst, BLM Washington Office; 

Steven Wells, Division Chief, Fluid 

Minerals, BLM Washington Office; 

Subijoy Dutta, Senior Petroleum 

Engineer, BLM Washington Office; Will 

Lambert, Petroleum Engineer, BLM 

Washington Office; Allen McKee, 

Petroleum Engineer, BLM Utah State 

Office; Don Judice, Field Manager, BLM 

Great Falls Field Office; Bev Winston, 

Public Affairs Specialist, BLM 

Washington Office; assisted by the 

BLM’s Division of Regulatory Affairs 

and the Department of the Interior’s 

Office of the Solicitor. 

List of Subjects 43 CFR Part 3160 

Administrative practice and 

procedure, Government contracts, 

Indians-lands, Mineral royalties, Oil and 

gas exploration, Penalties, Public landsmineral resources, Reporting and 

recordkeeping requirements. 

For the reasons stated in the 

preamble, and under the authorities 

stated below, the Bureau of Land 

Management amends 43 CFR part 3160 

as follows: 

PART 3160—ONSHORE OIL AND GAS 

OPERATIONS 

■ 1. The authority citation for part 3160 

is revised to read as follows: 

Authority: 25 U.S.C. 396d and 2107; 30 

U.S.C. 189, 306, 359, and 1751; and 43 U.S.C. 

1732(b), 1733, and 1740. 

Subpart 3160—Onshore Oil and Gas 

Operations: General 

§ 3160.0–3 [Amended] 

■ 2. In § 3160.0–3 add ‘‘the Federal 

Land Policy and Management Act (43 

U.S.C. 1701 et seq.),’’ after ‘‘the Mineral 

Leasing Act for Acquired lands, as 

amended (30 U.S.C. 351–359),’’. 

■ 3. Amend § 3160.0–5 by adding 

definitions of ‘‘annulus,’’ ‘‘bradenhead,’’ 

‘‘Cement Evaluation Log (CEL),’’ 

‘‘confining zone,’’ ‘‘hydraulic 

fracturing,’’ ‘‘hydraulic fracturing 

fluid,’’ ‘‘isolating or to isolate,’’ ‘‘master 

hydraulic fracturing plan,’’ ‘‘proppant,’’ 

and ‘‘usable water,’’ in alphabetical 

order and by removing the definition of 

‘‘fresh water’’ to read as follows: 

§ 3160.0–5 Definitions. 

* * * * * 

Annulus means the space around a 

pipe in a wellbore, the outer wall of 

which may be the wall of either the 

borehole or casing; sometimes also 

called annular space. 

* * * * * 

Bradenhead means a heavy, flanged 

steel fitting connected to the first string 

of casing that allows the suspension of 

intermediate and production strings of 

casing and supplies the means for the 

annulus to be sealed. 

Cement Evaluation Log (CEL) means 

any one of a class of tools that verify the 

integrity of annular cement bonding, 

such as, but not limited to, a cement 

bond log (CBL), ultrasonic imaging log, 

variable density logs, CBLs with 

directional receiver array, ultrasonic 

pulse echo log, or isolation scanner. 

Confining zone means a geological 

formation, group of formations, or part 

of a formation that is capable of 

preventing fluid movement from any 

formation that will be hydraulically 

fractured into a usable water zone. 

* * * * * 

Hydraulic fracturing means those 

operations conducted in an individual 

wellbore designed to increase the flow 

of hydrocarbons from the rock formation 

to the wellbore through modifying the 

permeability of reservoir rock by 

applying fluids under pressure to 

fracture it. Hydraulic fracturing does not 

include enhanced secondary recovery 

such as water flooding, tertiary 

recovery, recovery through steam 

injection, or other types of well 

stimulation operations such as 

acidizing. 

Hydraulic fracturing fluid means the 

liquid or gas, and any associated solids, 

used in hydraulic fracturing, including 

constituents such as water, chemicals, 

and proppants. 

Isolating or to isolate means using 

cement to protect, separate, or segregate 

usable water and mineral resources. 

* * * * * 

Master hydraulic fracturing plan 

means a plan containing the information 

required in section 3162.3–3(d) of this 

part for a group of wells where the 

geologic characteristics for each well are 

substantially similar. 

* * * * * 

Proppant means a granular substance 

(most commonly sand, sintered bauxite, 

or ceramic) that is carried in suspension 

by the fracturing fluid that serves to 

keep the cracks in the geologic 

formation open when fracturing fluid is 

withdrawn after a hydraulic fracture 

operation. 

* * * * * 

Usable water means 

(1) Generally those waters containing 

up to 10,000 parts per million (ppm) of 

total dissolved solids. Usable water 

includes, but is not limited to: 

(i) Underground water that meets the 

definition of ‘‘underground source of 

drinking water’’ as defined at 40 CFR 

144.3; 

(ii) Underground sources of drinking 

water under the law of the State (for 

Federal lands) or tribe (for Indian 

lands); and 

(iii) Water in zones designated by the 

State (for Federal lands) or tribe (for 

Indian lands) as requiring isolation or 

protection from hydraulic fracturing 

operations. 

(2) The following geologic zones are 

deemed not to contain usable water: 

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16218 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

(i) Zones from which the BLM has 

authorized an operator to produce oil 

and gas, provided that the operator has 

obtained all other authorizations 

required by the Environmental 

Protection Agency, the State (for Federal 

lands), or the tribe (for Indian lands) to 

conduct hydraulic fracturing operations 

in the specific zone; 

(ii) Zones designated as exempted 

aquifers pursuant to 40 CFR 144.7; and 

(iii) Zones that do not meet the 

definition of underground source of 

drinking water at 40 CFR 144.3 which 

the State (for Federal lands) or the tribe 

(for Indian lands) has designated as 

exempt from any requirement to be 

isolated or protected from hydraulic 

fracturing operations. 

* * * * * 

Subpart 3162—Requirements for 

Operating Rights Owners and 

Operators 

■ 4. Amend § 3162.3–2 by revising the 

first sentence of paragraph (a) and 

revising paragraph (b) to read as follows: 

§ 3162.3–2 Subsequent well operations. 

(a) A proposal for further well 

operations must be submitted by the 

operator on a Sundry Notice and Report 

on Wells (Form 3160–5) as a Notice of 

Intent for approval by the authorized 

officer prior to commencing operations 

to redrill, deepen, perform casing 

repairs, plug-back, alter casing, 

recomplete in a different interval, 

perform water shut off, combine 

production between zones, and/or 

convert to injection. * * * 

(b) Unless additional surface 

disturbance is involved and if the 

operations conform to the standard of 

prudent operating practice, prior 

approval is not required for acidizing 

jobs or recompletion in the same 

interval; however, a subsequent report 

on these operations must be filed using 

a Sundry Notice and Report on Wells 

(Form 3160–5). 

* * * * * 

■ 5. Revise § 3162.3–3 to read as 

follows: 

§ 3162.3–3 Subsequent well operations; 

Hydraulic fracturing. 

(a) Activities to which this section 

applies. This section, or portions of this 

section, apply to hydraulic fracturing as 

shown in the following table: 

If . . . Then 

(1) No APD was submitted as of June 24, 2015 .............................................................. The operator must comply with all paragraphs of this 

section. 

(2) An APD was submitted but not approved as of June 24, 2015.

(3) An APD or APD extension was approved before June 24, 2015, but the authorized 

drilling operations did not begin until after June 24, 2015.

To conduct hydraulic fracturing within 90 days after the 

effective date of this rule, the operator must comply 

with all paragraphs of this section, except (c) and (d). 

(4) Authorized drilling operations began, but were not completed before June 24, 2015 

(5) Authorized drilling operations were completed after September 22, 2015.

(6) Authorized drilling activities were completed before September 22, 2015 ................. The operator must comply with all paragraphs of this 

section. 

(b) Isolation of usable water to prevent 

contamination. All hydraulic fracturing 

operations must meet the performance 

standard in section 3162.5–2(d) of this 

title. 

(c) How an operator must submit a 

request for approval of hydraulic 

fracturing. A request for approval of 

hydraulic fracturing must be submitted 

by the operator and approved by the 

authorized officer before 

commencement of operations. The 

operator may submit the request in one 

of the following ways: 

(1) With an application for permit to 

drill; or 

(2) With a Sundry Notice and Report 

on Wells (Form 3160–5) as a notice of 

intent (NOI). 

(3) For approval of a group of wells 

submitted under either paragraph (c)(1) 

or (2) of this section, the operator may 

submit a master hydraulic fracturing 

plan. Submission of a master hydraulic 

fracturing plan does not obviate the 

need to obtain an approved APD from 

the BLM for each individual well. 

(4) If an operator has received 

approval from the authorized officer for 

hydraulic fracturing operations, and the 

operator has significant new 

information about the geology of the 

area, the stimulation operation or 

technology to be used, or the anticipated 

impacts of the hydraulic fracturing 

operation to any resource, then the 

operator must submit a new NOI (Form 

3160–5). Significant new information 

includes, but is not limited to, 

information that changes the proposed 

drilling or completion of the well, the 

hydraulic fracturing operation, or 

indicates increased risk of 

contamination of zones containing 

usable water or other minerals. 

(d) What a request for approval of 

hydraulic fracturing must include. The 

request for approval of hydraulic 

fracturing must include the information 

in this paragraph. If the information 

required by this paragraph has been 

assembled to comply with State law (on 

Federal lands) or tribal law (on Indian 

lands), such information may be 

submitted to the BLM authorized officer 

as provided to the State or tribal 

officials as part of the APD or NOI 

(Form 3160–5). 

(1) The following information 

regarding wellbore geology: 

(i) The geologic names, a geologic 

description, and the estimated depths 

(measured and true vertical) to the top 

and bottom of the formation into which 

hydraulic fracturing fluids are to be 

injected; 

(ii) The estimated depths (measured 

and true vertical) to the top and bottom 

of the confining zone(s); and 

(iii) The estimated depths (measured 

and true vertical) to the top and bottom 

of all occurrences of usable water based 

on the best available information. 

(2) A map showing the location, 

orientation, and extent of any known or 

suspected faults or fractures within onehalf mile (horizontal distance) of the 

wellbore trajectory that may transect the 

confining zone(s). The map must be of 

a scale no smaller than 1:24,000. 

(3) Information concerning the source 

and location of water supply, such as 

reused or recycled water, rivers, creeks, 

springs, lakes, ponds, and water supply 

wells, which may be shown by quarterquarter section on a map or plat, or 

which may be described in writing. It 

must also identify the anticipated access 

route and transportation method for all 

water planned for use in hydraulically 

fracturing the well; 

(4) A plan for the proposed hydraulic 

fracturing design that includes, but is 

not limited to, the following: 

(i) The estimated total volume of fluid 

to be used; 

(ii) The maximum anticipated surface 

pressure that will be applied during the 

hydraulic fracturing process; 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16219 

(iii) A map at a scale no smaller than 

1:24,000 showing: 

(A) The trajectory of the wellbore into 

which hydraulic fracturing fluids are to 

be injected; 

(B) The estimated direction and 

length of the fractures that will be 

propagated and a notation indicating the 

true vertical depth of the top and bottom 

of the fractures; and 

(C) All existing wellbore trajectories, 

regardless of type, within one-half mile 

(horizontal distance) of any portion of 

the wellbore into which hydraulic 

fracturing fluids are to be injected. The 

true vertical depth of each wellbore 

identified on the map must be 

indicated. 

(iv) The estimated minimum vertical 

distance between the top of the fracture 

zone and the nearest usable water zone; 

and 

(v) The measured depth of the 

proposed perforated or open-hole 

interval. 

(5) The following information 

concerning the handling of fluids 

recovered between the commencement 

of hydraulic fracturing operations and 

the approval of a plan for the disposal 

of produced fluid under BLM 

requirements: 

(i) The estimated volume of fluid to be 

recovered; 

(ii) The proposed methods of 

handling the recovered fluids as 

required under paragraph (h) of this 

section; and 

(iii) The proposed disposal method of 

the recovered fluids, including, but not 

limited to, injection, storage, and 

recycling. 

(6) If the operator submits a request 

for approval of hydraulic fracturing with 

an NOI (Form 3160–5), the following 

information must also be submitted: 

(i) A surface use plan of operations, if 

the hydraulic fracturing operation 

would cause additional surface 

disturbance; and 

(ii) Documentation required in 

paragraph (e) or other documentation 

demonstrating to the authorized officer 

that the casing and cement have isolated 

usable water zones, if the proposal is to 

hydraulically fracture a well that was 

completed without hydraulic fracturing. 

(7) The authorized officer may request 

additional information prior to the 

approval of the NOI (Form 3160–5) or 

APD. 

(e) Monitoring and verification of 

cementing operations prior to hydraulic 

fracturing. (1)(i) During cementing 

operations on any casing used to isolate 

and protect usable water zones, the 

operator must monitor and record the 

flow rate, density, and pump pressure, 

and submit a cement operation 

monitoring report for each casing string 

used to isolate and protect usable water 

to the authorized officer prior to 

commencing hydraulic fracturing 

operations. The cement operation 

monitoring report must be provided at 

least 48 hours prior to commencing 

hydraulic fracturing operations unless 

the authorized officer approves a shorter 

time. 

(ii) For any well completed pursuant 

to an APD that did not authorize 

hydraulic fracturing operations, the 

operator must submit documentation to 

demonstrate that adequate cementing 

was achieved for all casing strings 

designed to isolate and protect usable 

water. The operator must submit the 

documentation with its request for 

approval of hydraulic fracturing 

operations, or no less than 48 hours 

prior to conducting hydraulic fracturing 

operations if no prior approval is 

required, pursuant to paragraph (a) of 

this section. The authorized officer may 

approve the hydraulic fracturing of the 

well only if the documentation provides 

assurance that the cementing was 

sufficient to isolate and to protect usable 

water, and may require such additional 

tests, verifications, cementing or other 

protection or isolation operations, as the 

authorized officer deems necessary. 

(2) Prior to starting hydraulic 

fracturing operations, the operator must 

determine and document that there is 

adequate cement for all casing strings 

used to isolate and protect usable water 

zones as follows: 

(i) Surface casing. The operator must 

observe cement returns to surface and 

document any indications of inadequate 

cement (such as, but not limited to, lost 

returns, cement channeling, gas cut 

mud, failure of equipment, or fallback 

from the surface exceeding 10 percent of 

surface casing setting depth or 200 feet, 

whichever is less). If there are 

indications of inadequate cement, then 

the operator must determine the top of 

cement with a CEL, temperature log, or 

other method or device approved in 

advance by the authorized officer. 

(ii) Intermediate and production 

casing. (A) If the casing is not cemented 

to surface, then the operator must run a 

CEL to demonstrate that there is at least 

200 feet of adequately bonded cement 

between the zone to be hydraulically 

fractured and the deepest usable water 

zone. 

(B) If the casing is cemented to 

surface, then the operator must follow 

the requirements of paragraph (e)(2)(i) of 

this section. 

(3) For any well, if there is an 

indication of inadequate cement on any 

casing used to isolate usable water, then 

the operator must: 

(i) Notify the authorized officer within 

24 hours of discovering the inadequate 

cement; 

(ii) Submit an NOI (Form 3160–5) to 

the authorized officer requesting 

approval of a plan to perform remedial 

action to achieve adequate cement. The 

plan must include the supporting 

documentation and logs required under 

paragraph (e)(2) of this section. In 

emergency situations, an operator may 

request oral approval from the 

authorized officer for actions to be 

undertaken to remediate the cement. 

However, such requests must be 

followed by a written notice filed not 

later than the fifth business day 

following oral approval; 

(iii) Verify that the remedial action 

was successful with a CEL or other 

method approved in advance by the 

authorized officer; 

(iv) Submit a Sundry Notice and 

Report on Wells (Form 3160–5) as a 

subsequent report for the remedial 

action including: 

(A) A signed certification that the 

operator corrected the inadequate 

cement job in accordance with the 

approved plan; and 

(B) The results from the CEL or other 

method approved by the authorized 

officer showing that there is adequate 

cement. 

(v) The operator must submit the 

results from the CEL or other method 

approved by the authorized officer (see 

paragraph (e)(3)(iv)(B) of this section) at 

least 72 hours before starting hydraulic 

fracturing operations. 

(f) Mechanical integrity testing prior 

to hydraulic fracturing. Prior to 

hydraulic fracturing, the operator must 

perform a successful mechanical 

integrity test, as follows: 

(1) If hydraulic fracturing through the 

casing is proposed, the casing must be 

tested to not less than the maximum 

anticipated surface pressure that will be 

applied during the hydraulic fracturing 

process. 

(2) If hydraulic fracturing through a 

fracturing string is proposed, the 

fracturing string must be inserted into a 

liner or run on a packer-set not less than 

100 feet below the cement top of the 

production or intermediate casing. The 

fracturing string must be tested to not 

less than the maximum anticipated 

surface pressure minus the annulus 

pressure applied between the fracturing 

string and the production or 

intermediate casing. 

(3) The mechanical integrity test will 

be considered successful if the pressure 

applied holds for 30 minutes with no 

more than a 10 percent pressure loss. 

(g) Monitoring and recording during 

hydraulic fracturing. 

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16220 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

(1) During any hydraulic fracturing 

operation, the operator must 

continuously monitor and record the 

annulus pressure at the bradenhead. 

The pressure in the annulus between 

any intermediate casings and the 

production casing must also be 

continuously monitored and recorded. 

A continuous record of all annuli 

pressure during the fracturing operation 

must be submitted with the required 

Subsequent Report Sundry Notice (Form 

3160–5) identified in paragraph (i) of 

this section. 

(2) If during any hydraulic fracturing 

operation any annulus pressure 

increases by more than 500 pounds per 

square inch as compared to the pressure 

immediately preceding the stimulation, 

the operator must stop the hydraulic 

fracturing operation, take immediate 

corrective action to control the 

situation, orally notify the authorized 

officer as soon as practicable, but no 

later than 24 hours following the 

incident, and determine the reasons for 

the pressure increase. Prior to 

recommencing hydraulic fracturing 

operations, the operator must perform 

any remedial action required by the 

authorized officer, and successfully 

perform a mechanical integrity test 

under paragraph (f) of this section. 

Within 30 days after the hydraulic 

fracturing operations are completed, the 

operator must submit a report 

containing all details pertaining to the 

incident, including corrective actions 

taken, as part of a Subsequent Report 

Sundry Notice (Form 3160–5). 

(h) Management of Recovered Fluids. 

Except as provided in paragraphs (h)(1) 

and ((2) of this section, all fluids 

recovered between the commencement 

of hydraulic fracturing operations and 

the authorized officer’s approval of a 

produced water disposal plan under 

BLM requirements must be stored in 

rigid enclosed, covered, or netted and 

screened above-ground tanks. The tanks 

may be vented, unless Federal law, or 

State regulations (on Federal lands) or 

tribal regulations (on Indian lands) 

require vapor recovery or closed-loop 

systems. The tanks must not exceed a 

500 barrel (bbl) capacity unless 

approved in advance by the authorized 

officer. 

(1) The authorized officer may 

approve an application to use lined pits 

only if the applicant demonstrates that 

use of a tank as described in this 

paragraph (h) is infeasible for 

environmental, public health or safety 

reasons and only if, at a minimum, all 

of the following conditions apply: 

(i) The distance from the pit to 

intermittent or ephemeral streams or 

water sources would be at least 300 feet; 

(ii) The distance from the pit to 

perennial streams, springs, fresh water 

sources, or wetlands would be at least 

500 feet; 

(iii) There is no usable groundwater 

within 50 feet of the surface in the area 

where the pit would be located; 

(iv) The distance from the pit to any 

occupied residence, school, park, school 

bus stop, place of business, or other 

areas where the public could reasonably 

be expected to frequent would be greater 

than 300 feet; 

(v) The pit would not be constructed 

in fill or unstable areas; 

(vi) The construction of the pit would 

not adversely impact the hydrologic 

functions of a 100-year floodplain; and 

(vii) Pit use and location complies 

with applicable local, State (on Federal 

lands), tribal (on Indian lands) and other 

Federal statutes and regulations 

including those that are more stringent 

than these regulations. 

(2) Pits approved by the authorized 

officer must be: 

(i) Lined with a durable, leak-proof 

synthetic material and equipped with a 

leak detection system; and 

(ii) Routinely inspected and 

maintained, as required by the 

authorized officer, to ensure that there 

is no fluid leakage into the environment. 

The operator must document all 

inspections. 

(i) Information that must be provided 

to the authorized officer after hydraulic 

fracturing is completed. The 

information required in paragraphs (i)(1) 

through (10) of this section must be 

submitted to the authorized officer 

within 30 days after the completion of 

the last stage of hydraulic fracturing 

operations for each well. The 

information is required for each well, 

even if the authorized officer approved 

fracturing of a group of wells (see 

§ 3162.3–3(c)). The information required 

in paragraph (i)(1) of this section must 

be submitted to the authorized officer 

through FracFocus or another BLMdesignated database, or in a Subsequent 

Report Sundry Notice (Form 3160–5). If 

information is submitted through 

FracFocus or another BLM-designated 

database, the operator must specify that 

the information is for a Federal or an 

Indian well, certify that the information 

is both timely filed and correct, and 

certify compliance with applicable law 

as required by paragraph (i)(8)(ii) or (iii) 

of this section using FracFocus or 

another BLM-designated database. The 

information required in paragraphs (i)(2) 

though (10) of this section must be 

submitted to the authorized officer in a 

Subsequent Report Sundry Notice (Form 

3160–5). The operator is responsible for 

the information submitted by a 

contractor or agent, and the information 

will be considered to have been 

submitted directly from the operator to 

the BLM. The operator must submit the 

following information: 

(1) The true vertical depth of the well, 

total water volume used, and a 

description of the base fluid and each 

additive in the hydraulic fracturing 

fluid, including the trade name, 

supplier, purpose, ingredients, 

Chemical Abstract Service Number 

(CAS), maximum ingredient 

concentration in additive (percent by 

mass), and maximum ingredient 

concentration in hydraulic fracturing 

fluid (percent by mass). 

(2) The actual source(s) and 

location(s) of the water used in the 

hydraulic fracturing fluid; 

(3) The maximum surface pressure 

and rate at the end of each stage of the 

hydraulic fracturing operation and the 

actual flush volume. 

(4) The actual, estimated, or 

calculated fracture length, height and 

direction. 

(5) The actual measured depth of 

perforations or the open-hole interval. 

(6) The total volume of fluid 

recovered between the completion of 

the last stage of hydraulic fracturing 

operations and when the operator starts 

to report water produced from the well 

to the Office of Natural Resources 

Revenue. If the operator has not begun 

to report produced water to the Office 

of Natural Resources Revenue when the 

Subsequent Report Sundry Notice is 

submitted, the operator must submit a 

supplemental Subsequent Report 

Sundry Notice (Form 3160–5) to the 

authorized officer documenting the total 

volume of recovered fluid. 

(7) The following information 

concerning the handling of fluids 

recovered, covering the period between 

the commencement of hydraulic 

fracturing and the implementation of 

the approved plan for the disposal of 

produced water under BLM 

requirements: 

(i) The methods of handling the 

recovered fluids, including, but not 

limited to, transfer pipes and tankers, 

holding pond use, re-use for other 

stimulation activities, or injection; and 

(ii) The disposal method of the 

recovered fluids, including, but not 

limited to, the percent injected, the 

percent stored at an off-lease disposal 

facility, and the percent recycled. 

(8) A certification signed by the 

operator that: 

(i) The operator complied with the 

requirements in paragraphs (b), (e), (f), 

(g), and (h) of this section; 

(ii) For Federal lands, the hydraulic 

fracturing fluid constituents, once they 

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Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 16221 

arrived on the lease, complied with all 

applicable permitting and notice 

requirements as well as all applicable 

Federal, State, and local laws, rules, and 

regulations; and 

(iii) For Indian lands, the hydraulic 

fracturing fluid constituents, once they 

arrived on the lease, complied with all 

applicable permitting and notice 

requirements as well as all applicable 

Federal and tribal laws, rules, and 

regulations. 

(9) The operator must submit the 

result of the mechanical integrity test as 

required by paragraph (f) of this section. 

(10) The authorized officer may 

require the operator to provide 

documentation substantiating any 

information submitted under paragraph 

(i) of this section. 

(j) Identifying information claimed to 

be exempt from public disclosure. 

(1) For the information required in 

paragraph (i) of this section, the 

operator and the owner of the 

information will be deemed to have 

waived any right to protect from public 

disclosure information submitted with a 

Subsequent Report Sundry Notice (Form 

3160–5) or through FracFocus or 

another BLM-designated database. For 

information required in paragraph (i) of 

this section that the owner of the 

information claims to be exempt from 

public disclosure and is withheld from 

the BLM, a corporate officer, managing 

partner, or sole proprietor of the 

operator must sign and the operator 

must submit to the authorized officer 

with the Subsequent Report Sundry 

Notice (Form 3160–5) required in 

paragraph (i) of this section an affidavit 

that: 

(i) Identifies the owner of the 

withheld information and provides the 

name, address and contact information 

for a corporate officer, managing 

partner, or sole proprietor of the owner 

of the information; 

(ii) Identifies the Federal statute or 

regulation that would prohibit the BLM 

from publicly disclosing the information 

if it were in the BLM’s possession; 

(iii) Affirms that the operator has been 

provided the withheld information from 

the owner of the information and is 

maintaining records of the withheld 

information, or that the operator has 

access and will maintain access to the 

withheld information held by the owner 

of the information; 

(iv) Affirms that the information is not 

publicly available; 

(v) Affirms that the information is not 

required to be publicly disclosed under 

any applicable local, State or Federal 

law (on Federal lands), or tribal or 

Federal law (on Indian lands); 

(vi) Affirms that the owner of the 

information is in actual competition and 

identifies competitors or others that 

could use the withheld information to 

cause the owner of the information 

substantial competitive harm; 

(vii) Affirms that the release of the 

information would likely cause 

substantial competitive harm to the 

owner of the information and provides 

the factual basis for that affirmation; and 

(viii) Affirms that the information is 

not readily apparent through reverse 

engineering with publicly available 

information. 

(2) If the operator relies upon 

information from third parties, such as 

the owner of the withheld information, 

to make the affirmations in paragraphs 

(j)(1)(vi) through (viii) of this section, 

the operator must provide a written 

affidavit from the third party that sets 

forth the relied-upon information. 

(3) The BLM may require any operator 

to submit to the BLM any withheld 

information, and any information 

relevant to a claim that withheld 

information is exempt from public 

disclosure. 

(4) If the BLM determines that the 

information submitted under paragraph 

(j)(3) of this section is not exempt from 

disclosure, the BLM will make the 

information available to the public after 

providing the operator and owner of the 

information with no fewer than 10 

business days’ notice of the BLM’s 

determination. 

(5) The operator must maintain 

records of the withheld information 

until the later of the BLM’s approval of 

a final abandonment notice, or 6 years 

after completion of hydraulic fracturing 

operations on Indian lands, or 7 years 

after completion of hydraulic fracturing 

operations on Federal lands. Any 

subsequent operator will be responsible 

for maintaining access to records 

required by this paragraph during its 

operation of the well. The operator will 

be deemed to be maintaining the records 

if it can promptly provide the complete 

and accurate information to BLM, even 

if the information is in the custody of its 

owner. 

(6) If any of the chemical identity 

information required in paragraph (i)(1) 

of this section is withheld, the operator 

must provide the generic chemical name 

in the submission required by paragraph 

(i)(1) of this section. The generic 

chemical name must be only as 

nonspecific as is necessary to protect 

the confidential chemical identity, and 

should be the same as or no less 

descriptive than the generic chemical 

name provided to the Environmental 

Protection Agency. 

(k) Requesting a variance from the 

requirements of this section. 

(1) Individual variance: The operator 

may make a written request to the 

authorized officer for a variance from 

the requirements under this section. A 

request for an individual variance must 

specifically identify the regulatory 

provision of this section for which the 

variance is being requested, explain the 

reason the variance is needed, and 

demonstrate how the operator will 

satisfy the objectives of the regulation 

for which the variance is being 

requested. 

(2) State or tribal variance: In 

cooperation with a State (for Federal 

lands) or a tribe (for Indian lands), the 

appropriate BLM State Director may 

issue a variance that would apply to all 

wells within a State or within Indian 

lands, or to specific fields or basins 

within the State or the Indian lands, if 

the BLM finds that the variance meets 

the criteria in paragraph (k)(3) of this 

section. A State or tribal variance 

request or decision must specifically 

identify the regulatory provision(s) of 

this section for which the variance is 

being requested, explain the reason the 

variance is needed, and demonstrate 

how the operator will satisfy the 

objectives of the regulation for which 

the variance is being requested. A State 

or tribal variance may be initiated by the 

State, tribe, or the BLM. 

(3) The authorized officer (for an 

individual variance), or the State 

Director (for a State or tribal variance), 

after considering all relevant factors, 

may approve the variance, or approve it 

with one or more conditions of 

approval, only if the BLM determines 

that the proposed alternative meets or 

exceeds the objectives of the regulation 

for which the variance is being 

requested. The decision whether to 

grant or deny the variance request must 

be in writing and is entirely within the 

BLM’s discretion. The decision on a 

variance request is not subject to 

administrative appeals either to the 

State Director (for an individual 

variance) or under 43 CFR part 4. 

(4) A variance under this section does 

not constitute a variance to provisions 

of other regulations, laws, or orders. 

(5) Due to changes in Federal law, 

technology, regulation, BLM policy, 

field operations, noncompliance, or 

other reasons, the BLM reserves the 

right to rescind a variance or modify any 

conditions of approval. The authorized 

officer must provide a written 

justification before a variance is 

rescinded or a condition of approval is 

modified. 

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16222 Federal Register / Vol. 80, No. 58 / Thursday, March 26, 2015 / Rules and Regulations 

■ 6. Amend § 3162.5–2 by revising the 

first sentence of paragraph (d) to read as 

follows: 

§ 3162.5–2 Control of wells. 

* * * * * 

(d) Protection of usable water and 

other minerals. The operator must 

isolate all usable water and other 

mineral-bearing formations and protect 

them from contamination. * * * 

Janice M. Schneider, 

Assistant Secretary, Land and Minerals 

Management. 

[FR Doc. 2015–06658 Filed 3–20–15; 4:15 pm] 

BILLING CODE 4310–84–P 

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