[Federal Register Volume 80, Number 58 (Thursday, March 26, 2015)]
[Rules and Regulations]
[Pages 16128-16222]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-06658]



[[Page 16127]]

Vol. 80

Thursday,

No. 58

March 26, 2015

Part III





Department of the Interior





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Bureau of Land Management





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43 CFR Part 3160





Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands; Final 
Rule

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

[[Page 16128]]


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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.

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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 re-complete 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 pre-date 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,

[[Page 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:
    <bullet> 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;
    <bullet> 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);
    <bullet> Monitor cementing operations during well construction;
    <bullet> Take remedial action if there are indications of 
inadequate cementing, and demonstrate to the BLM that the remedial 
action was successful;
    <bullet> Perform a successful mechanical integrity test (MIT) prior 
to the hydraulic fracturing operation;
    <bullet> Monitor annulus pressure during a hydraulic fracturing 
operation;
    <bullet> 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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    <bullet> Disclose the chemicals used to the BLM and the public, 
with limited exceptions for material demonstrated through affidavit to 
be trade secrets;
    <bullet> 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:
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    \1\ Secretary of Energy's Advisory Board recommendations can be 
downloaded from http://energy.gov/seab/downloads/fracfocus-20-task-force-report.
    \2\ http://www.gwpc.org/major-improvements-fracfocus-announced.
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    <bullet> Reducing the number of human errors in disclosures
    <bullet> Expanding the public's ability to search records
    <bullet> Providing public extraction of data in a ``machine 
readable'' format and
    <bullet> 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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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 proppant-filled 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

[[Page 16132]]

to develop resources on public and Indian lands in a safe and 
responsible way. During the proposed rule stage, the BLM initiated 
government-to-government 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-to-government 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 Self-Determination 
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,

[[Page 16133]]

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\
---------------------------------------------------------------------------

    \3\ See updated FracFocus link: http://www.fracfocus.org/welcome.

------------------------------------------------------------------------
                                               States proposing to use
     States currently using FracFocus                 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.............................
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.
---------------------------------------------------------------------------

    \4\ Secretary of Energy's Advisory Board recommendations (http://energy.gov/seab/downloads/fracfocus-20-task-force-report) includes 
the areas of improvement.
---------------------------------------------------------------------------

    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

[[Page 16134]]

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:
    <bullet> 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.
    <bullet> Minimum specifications for blowout prevention equipment 
that will be used to keep control of well pressures encountered while 
drilling.
    <bullet> A description of the proposed casing program, including 
the size, grade, weight, and setting depth of each casing string.
    <bullet> 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.

[[Page 16135]]

    <bullet> Information regarding the proposed drilling fluid and 
proposed testing, logging, and coring procedures.
    <bullet> An estimate of the expected bottom-hole 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.
    <bullet> 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:
    <bullet> Location and description of, as well as maintenance plan 
for, existing and new roads the operator plans to use to access the 
proposed well.
    <bullet> 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.
    <bullet> 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.
    <bullet> Information concerning the water supply, such as rivers, 
creeks, springs, lakes, ponds, and wells that the operator plans to use 
for drilling the well.
    <bullet> 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.
    <bullet> A diagram in the surface use plan of the proposed well 
site layout.
    <bullet> 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 site-specific 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.

[[Page 16136]]

    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:
    <bullet> 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.
    <bullet> 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.
    <bullet> 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.
    <bullet> 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

[[Page 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    This final rule makes
                                 Definitions.       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
                                                    Sec.   3162.2-
                                                    3(e)(2) to the
                                                    definitions section.
                                                    The term ``confining
                                                    zone'' is now
                                                    defined because that
                                                    term is used in
                                                    revised Sec.
                                                    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      43 CFR 3162.3-2    Paragraph (a) of this
 Well Operations.                Subsequent Well    section is modified
                                 Operations.        slightly by removing
                                                    the phrase ``the
                                                    operator'' because
                                                    it is redundant.
43 CFR 3162.3-3(a) Hydraulic    43 CFR 3162.3-     The final rule
 Fracturing.                     3(a) Subsequent    clarifies the
                                 Well Operations;   application of this
                                 Hydraulic          rule to wells at
                                 Fracturing.        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    43 CFR 3162.3-     The term
 of Usable Water to Prevent      3(b) Isolation     ``refracturing'' is
 Contamination.                  of Usable Water    deleted.
                                 to Prevent
                                 Contamination.

[[Page 16138]]

 
43 CFR 3162.3-3(c) When an      43 CFR 3162.3-     Paragraphs (c)(1) and
 Operator Must Submit            3(c) How an        (2) of this section
 Notification for Approval of    Operator Must      are revised non-
 Hydraulic Fracturing.           Submit a Request   substantively and
                                 for Approval of    for clarity.
                                 Hydraulic          Paragraph (c)(3) is
                                 Fracturing.        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     43 CFR 3162.3-     Consistent with other
 Notice of Intent Sundry Must    3(d) What a        changes in this
 Include.                        Request for        rule, the final rule
                                 Approval of        replaces the
                                 Hydraulic          procedure for
                                 Fracturing Must    submitting an NOI
                                 Include.           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 one-
                                                    half mile of the
                                                    wellbore that will
                                                    be hydraulically
                                                    fractured.
43 CFR 3162.3-3(d)(2).........  43 CFR 3162.3-     The final rule
                                 3(d)(2).           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-     The final rule
                                 3(d)(3).           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-     The final rule
                                 3(d)(4).           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-     The final rule
                                 3(d)(5).           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-     The final rule
                                 3(d)(6).           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-     Because of new
                                 3(d)(7).           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.

[[Page 16139]]

 
43 CFR 3162.3(e) Monitoring of  43 CFR 3162.3-     The title of this
 Cementing Operations and        3(e) Monitoring    section is revised
 Cement Evaluation Log Prior     and Verification   to better reflect
 to Hydraulic Fracturing.        of Cementing       the content of the
                                 Operations Prior   final rule.
                                 to Hydraulic
                                 Fracturing.
43 CFR 3162.3-3(e)(1).........  43 CFR 3162.3-     This paragraph is
                                 3(e)(1).           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-     New paragraph (e)(2)
                                 3(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),  43 CFR 3162.3-     Final paragraph (3)
 and (e)(5).                     3(e)(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   43 CFR 3162.3-     Paragraph (1) of this
 Integrity Testing Prior to      3(f) Mechanical    section is revised
 Hydraulic Fracturing.           Integrity          to include the words
                                 Testing Prior to   ``that will be
                                 Hydraulic          applied during the
                                 Fracturing.        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   43 CFR 3162.3-     This paragraph has
 and Recording During            3(g) Monitoring    been revised to
 Hydraulic Fracturing.           and Recording      delete the term
                                 During Hydraulic   ``refracturing,''
                                 Fracturing.        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-     This section has
                                 3(h) Management    undergone numerous
                                 of Recovered       changes. The final
                                 Fluids.            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  43 CFR 3162.3-     The heading of this
 that Must be Provided to the    3(i) and (i)(1)    section is revised
 Authorized Officer After        Information that   to make it clearer.
 Completed Operations.           Must be Provided   Paragraph (i)(1) of
                                 to the             this section is also
                                 Authorized         revised to require
                                 Officer After      the operator to
                                 Hydraulic          provide information
                                 Fracturing is      about each additive
                                 Completed.         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-     This section has been
                                 3(i)(2), (i)(3),   revised to seek only
                                 and (i)(5).        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-     The final rule seeks
                                 3(i)(3).           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.

[[Page 16140]]

 
43 CFR 3162.3-3(i)(4).........  43 CFR 3162.3-     This section requires
                                 3(i)(4).           the report to
                                                    include the actual,
                                                    estimated, or
                                                    calculated fracture
                                                    length, height, and
                                                    direction. This
                                                    section remains as
                                                    proposed.
None..........................  43 CFR 3162.3-     New paragraph (5)
                                 3(i)(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-     New paragraph (6)
                                 3(i)(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-     The final rule
                                 3(i)(7).           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-     This final section is
                                 3(i)(7)(i).        renumbered, but is
                                                    similar to the
                                                    supplemental
                                                    proposed rule.
43 CFR 3162.3-3(i)(5)(iii)....  43 CFR 3162.3-     The final rule would
                                 3(i)(7)(ii).       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-     The final rule
                                 3(i)(8).           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-     The final rule
                                 3(i)(9).           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  43 CFR 3162.3-     The final rule at
 Information Claimed to be       3(j) Identifying   paragraph (j)(1)
 Exempt from Public Disclosure.  Information        strengthens the
                                 Claimed to be      affidavit provisions
                                 Exempt from        to ensure that
                                 Public             operators fully
                                 Disclosure.        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   43 CFR 3162.3-     The final rule
 a Variance from the             3(k) Requesting    revises the variance
 Requirements of this Section.   a Variance from    provisions to allow
                                 the Requirements   for individual
                                 of this Section.   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.

[[Page 16141]]

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

[[Page 16142]]

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.
    <bullet> 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.
    <bullet> 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.
    <bullet> 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.
---------------------------------------------------------------------------

    \5\ For 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.
---------------------------------------------------------------------------

    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

[[Page 16143]]

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

[[Page 16144]]

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\
---------------------------------------------------------------------------

    \6\ The 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.
---------------------------------------------------------------------------

    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 multi-stage 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

[[Page 16145]]

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 ``micro-
seismogram'' (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

[[Page 16146]]

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.

[[Page 16147]]

    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)

[[Page 16148]]

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:
    <bullet> 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;
    <bullet> 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
    <bullet> 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 down-hole 
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.

[[Page 16149]]

    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 one-half 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

[[Page 16150]]

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 one-half 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

[[Page 16151]]

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,''

[[Page 16152]]

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

[[Page 16153]]

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 quarter-quarter 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

[[Page 16154]]

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 
high-pressure 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 one-
half 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 site-specific 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,

[[Page 16155]]

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:
    <bullet> 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.;
    <bullet> 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;
    <bullet> 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 Operations-Well 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 re-completed 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

[[Page 16156]]

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

[[Page 16157]]

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

[[Page 16158]]

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 near-
surface 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 
self-certification 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

[[Page 16159]]

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).
---------------------------------------------------------------------------

    \7\ Hydraulic Fracturing Operations--Well Construction and 
Integrity Guidelines, API Guidance Document HF1 (1st ed., Oct. 
2009).
---------------------------------------------------------------------------

    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,

[[Page 16160]]

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 pressure-
actuated 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

[[Page 16161]]

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:
    <bullet> Submit monthly and annual production reports including 
volume of oil and gas to the BLM;
    <bullet> Monitor pressure of each well daily for the first 30 days 
of operation;
    <bullet> Maintain production and monitoring reports for 5 years;
    <bullet> Conduct periodic well tests to determine flow rate and 
pressure;
    <bullet> Maintain and test wellhead equipment over the life of the 
well;
    <bullet> Annually report casing pressures to the BLM and notify the 
BLM if pressures approach the design limits of the casing;
    <bullet> Install pressure relief valves, especially on high-
pressure or high-volume wells; and
    <bullet> Monitor all wells for corrosion and potential hazards.

[[Page 16162]]

    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

[[Page 16163]]

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 high-volume 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 
trailer-mounted 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.
---------------------------------------------------------------------------

    \8\ Link to the Final COGCC Policy: https://cogcc.state.co.us/RR_Docs_new/Policies/MLVTPolicyFinal20140613.pdf.
---------------------------------------------------------------------------

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

[[Page 16164]]

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 royalty-bearing 
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.
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[GRAPHIC] [TIFF OMITTED] TR26MR15.000

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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 multi-stage 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

[[Page 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 cross-references 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 self-
certification 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

[[Page 16168]]

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

[[Page 16169]]

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 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.
    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.

[[Page 16170]]

    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 post-fracking 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.

[[Page 16171]]

    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 post-
hydraulic 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

[[Page 16172]]

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 Sec.  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

[[Page 16173]]

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

[[Page 16174]]

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.

[[Page 16175]]

    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

[[Page 16176]]

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 notice-and-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.

[[Page 16177]]



------------------------------------------------------------------------
                                                     Final rule/Onshore
           Subject                  API HF-1               Order 2
------------------------------------------------------------------------
Surface casing..............  Set at least 100'     Usable water must be
                               below lowest USDW     isolated by casing
                               (deep water zones     (not necessarily by
                               can be isolated by    surface casing).
                               intermediate or
                               production 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      200 feet of
                               last cement system    adequately bonded
                               pumped during         cement between the
                               primary cementing     fractured zone and
                               which covers the      the deepest usable
                               lower sections of     water zone, could
                               the well) should be   be either
                               brought 500' above    production or
                               producing formation.  intermediate
                                                     casing.
                              Tail cement should
                               extend above the
                               top of confining
                               formation.
                              Should consider CBL   CEL required if
                               for cement            casing is used to
                               evaluation.           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   Formation integrity
                               test after drilling   test if exploratory
                               out.                  well or if the
                                                     blowout prevention
                                                     equipment is 5,000
                                                     psi or greater
                                                     (Onshore Order 2).
                              Take remedial action  Take remedial action
                               if pressure tests     if there are
                               fail.                 indications of
                                                     inadequate cement.
Pressure test prior to        Test all hydraulic    Mechanical Integrity
 hydraulic fracturing.         fracturing surface    Test: Pressure test
                               equipment.            casing or
                                                     fracturing string
                                                     to maximum
                                                     anticipated
                                                     pressure.
Baseline water monitoring...  Test water samples    ....................
                               from nearby water
                               sources prior to
                               drilling.
Monitoring during hydraulic   During hydraulic      Monitor and report
 fracturing.                   fracturing, monitor   actual pump
                               injection pressure,   pressure, fluid
                               slurry rate,          rate, and flush
                               proppant              volume.
                               concentration,
                               fluid rate, and
                               proppant rate.
                              Monitor annular       Monitor annular
                               pressure (all         pressure (all
                               annuli).              annuli).
                              Monitor unexplained   Annular pressure
                               deviations from       increase greater
                               plan.                 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.

[[Page 16178]]

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 self-reporting, 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 above-ground 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

[[Page 16179]]

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 site-specific 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.

[[Page 16180]]

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

[[Page 16181]]

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-by-case 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:
    <bullet> 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;
    <bullet> Dust abatement on county roads;
    <bullet> The power washing and inspection of all vehicles entering 
a well site to prevent non-native invasive plant species from becoming 
established;
    <bullet> The installation of sound dampening devices;
    <bullet> Prohibiting the use of jake (engine) brakes on trucks 
operating near residential areas;
    <bullet> Provisions to control stormwater runoff;
    <bullet> Capturing or controlling greenhouse gas emissions during 
hydraulic fracturing operations; and
    <bullet> 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

[[Page 16182]]

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 one-half 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

[[Page 16183]]

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 non-federal, 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 site-specific 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.
---------------------------------------------------------------------------

    \9\ American Petroleum Institute (API) guidance, ``Hydraulic 
Fracturing Operations-Well Construction and Integrity Guidelines, 
First Edition, October 2009.''
---------------------------------------------------------------------------

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

[[Page 16184]]

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-to-government 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

[[Page 16185]]

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-to-government 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 self-
determination 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 
Self-Determination 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

[[Page 16186]]

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

[[Page 16187]]

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

[[Page 16188]]

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

[[Page 16189]]

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\
---------------------------------------------------------------------------

    \10\ CEQ, Forty Most Asked Questions Concerning CEQ's National 
Environmental Policy Act Regulations, 46 FR 18026, 18027 (1981) (Q 
2a-).
---------------------------------------------------------------------------

    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.

[[Page 16190]]



------------------------------------------------------------------------
          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     Under this alternative, the BLM
 Stimulation Rule.                        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--         Under this alternative, the BLM
 Supplemental Proposed Hydraulic          would promulgate the
 Fracturing Rule.                         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             Under this alternative, the BLM
 Alternative, Final Hydraulic             would promulgate the final
 Fracturing Rule.                         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

[[Page 16191]]

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 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)). 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 hydrocarbon-bearing 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 decision-
makers 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

[[Page 16192]]

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

[[Page 16193]]

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.

[[Page 16194]]

    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:
---------------------------------------------------------------------------

    \11\ Osborn, S., et al. (2011). Methane contamination of 
drinking water accompanying gas-well drilling and hydraulic 
fracturing. Proceedings of the National Academy of Sciences.
    \12\ Warner, 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.
---------------------------------------------------------------------------

    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 
gas-well 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\
---------------------------------------------------------------------------

    \13\ U.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.
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    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 safety-critical stages of well construction and 
hydraulic fracturing.'' \14\
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    \14\ Secretary 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.
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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

[[Page 16195]]

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:
    <bullet> Not yet submitted an APD as of the effective date of this 
rule;
    <bullet> Submitted an APD, but the APD has yet to be approved as of 
the effective date of this rule;
    <bullet> 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

[[Page 16196]]

hydraulic fracturing within 90 days after the effective date;
    <bullet> Started (but does not complete) drilling before the 
effective date and does not conduct hydraulic fracturing within 90 days 
after the effective date;
    <bullet> Completed drilling 180 days prior to the effective date, 
and does not conduct hydraulic fracturing within 90 days after the 
effective date; or
    <bullet> 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.
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    \15\ The cost formulation for administrative requirements is 
detailed in the supporting statement for the Paperwork Reduction 
Act.
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    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

[[Page 16197]]

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.
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    \16\ Ibid, p. 8.
    \17\ Ibid, p. 9.
    \18\ Ibid, p. 10.
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    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

[[Page 16198]]

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:
    <bullet> Notify the authorized officer within 24 hours of 
discovering the inadequate cement;
    <bullet> 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;
    <bullet> Verify that the remedial action was successful with a CEL 
or other method approved in advance by the authorized officer; and
    <bullet> 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.
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    \19\ Percent 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).
---------------------------------------------------------------------------

    (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

[[Page 16199]]

the BLM is contained in the post-fracturing reporting requirements.
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    \20\ API Guidance Document HF1, p. 21.

(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 closed-loop 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\
---------------------------------------------------------------------------

    \21\ Center for Sustainable Shale Development Web site. Accessed 
on March 29, 2013, http://037186e.netsolhost.com/site/performance-standards/.
    \22\ A 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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \23\ The comment letter from ConocoPhillips, dated August 22, 
2013, is available in the rulemaking docket at www.regulations.gov.
---------------------------------------------------------------------------

    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, semi-rigid 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      $2,970,000  $51,000 x 6 = $306,000....  n/a
 cost.
Annual operating or Rental Cost.........         $20,000  $132,000 x 6 = $792,000     $16,425 x 500 = $8,212,500
                                                           (assumes $11,000 monthly    (assumes $45 daily rental
                                                           rental fee).                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

[[Page 16200]]

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).
---------------------------------------------------------------------------

    \24\ Skytruth.org, ``2013 Reports Data,'' accessed on November 
20, 2014.

      Figure 3--Average Water Used in Hydraulic Fracturing Operations, 2013, and Estimated Recovered Fluids
----------------------------------------------------------------------------------------------------------------
                                                                      Average        Range of recovered fluids
                                                                     volume of                 (bbl)
                                                                    water used   -------------------------------
                              State                                 (bbl) (data
                                                                  extracted from     Low (15%)      High (40%)
                                                                    FracFocus)
----------------------------------------------------------------------------------------------------------------
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            24,385           3,658           9,754
 state and the distribution of operations on Federal and Indian
 lands).........................................................
----------------------------------------------------------------------------------------------------------------
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\
---------------------------------------------------------------------------

    \25\ EPA Web site, ``Hydraulic Fracturing Research Study,'' 
accessed on November 20, 2014 at http://www.epa.gov/ogwdw000/uic/pdfs/hfresearchstudyfs.pdf.
    \26\ Halliburton, ``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-Oil-Gas-Facilities-Article.pdf.

<bullet> Bakken: 15-40 percent
<bullet> Eagle Ford: < 15 percent
<bullet> Permian Basin: 20-40 percent
<bullet> Marcellus: 10-40 percent
<bullet> 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 per-operation incremental costs of using rigid steel tanks 
instead of a pit. We estimated the baseline cost of

[[Page 16201]]

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.
---------------------------------------------------------------------------

    \27\ We 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).
---------------------------------------------------------------------------

    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

[[Page 16202]]

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
----------------------------------------------------------------------------------------------------------------
                                                      Job duration of 14 days         Job duration of 21 days
                                                 ---------------------------------------------------------------
                                                                      Average                         Average
                                                                     volume of                       volume of
                                                                     recovered                       recovered
                      State                          Estimated      fluids for       Estimated      fluids for
                                                     voluntary      operations       voluntary      operations
                                                    compliance     exceeding the    compliance     exceeding the
                                                        (%)          threshold          (%)          threshold
                                                                   (40% recovery                   (40% recovery
                                                                       rate)                           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                  70.3          57,283            65.4          53,398
 operations in FracFocus).......................
Weighted Average (based on distribution of                  93.5          55,631            90.6          47,757
 operations on Federal and Indian lands)........
----------------------------------------------------------------------------------------------------------------

    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 per-
operation cost might be $1,200 to $1,300. However, according to the

[[Page 16203]]

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 BLM-managed 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 pit-liner 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.
---------------------------------------------------------------------------

    \28\ The 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.
    \29\ API, HF2.
---------------------------------------------------------------------------

    (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 closed-loop 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

[[Page 16204]]

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.
---------------------------------------------------------------------------

    \30\ The Carlsbad Field Office submitted an Initial Report for 
the major undesirable event, occurring on lease NMNM0631.
---------------------------------------------------------------------------

    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:
    <bullet> 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.

[[Page 16205]]

    <bullet> 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.
    <bullet> Storage tank costs. The BLM estimated voluntary compliance 
based on the average volume of recovered fluids and a number of cost 
assumptions, including the per-operation 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.
    <bullet> 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.

[[Page 16206]]

    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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
         Federal lands, by state           operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
         Federal lands, by state           operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
        Reservation or BIA agency          operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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

[[Page 16207]]

 
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 per-operation 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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
              Jurisdiction                 operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 16208]]


             Table 5B--Potential Upper Bound Estimate (Using FY 2012 Level of Activity)--Estimated Annual Incremental Costs, by Requirement
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
              Jurisdiction                 operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                       Remedial
                                           Number of    Application     action        CEL on        Storage     Post-fracture     Variance
              Jurisdiction                 operations    (sundry)     reporting    intermediate       tank        reporting       requests   Total costs
                                            per year                   (sundry)       casing                       (sundry)       (sundry)
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                     Remedial
                                    Application       action       Post-fracture     Variance
      Party assuming burden          (sundry)        reporting       reporting       requests       Total costs
                                                     (sundry)        (sundry)        (sundry)
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                     Remedial
                                    Application       action       Post-fracture     Variance
      Party assuming burden          (sundry)        reporting       reporting       requests       Total costs
                                                     (sundry)        (sundry)        (sundry)
----------------------------------------------------------------------------------------------------------------
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,

[[Page 16209]]

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 one-time 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).
---------------------------------------------------------------------------

    \31\ NAICS codes: 211111--Crude Petroleum and Natural Gas 
Extraction, 211112--Natural Gas Liquid Extraction, and 213111--
Drilling Oil and Gas Wells.
---------------------------------------------------------------------------

    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
----------------------------------------------------------------------------------------------------------------
                                                                                                     Hydraulic
                                                                     Hydraulic       Hydraulic      fracturing
                                                    Company net     fracturing      fracturing       operation
              Descriptive statistic                   income       operation on    operation on      (without
                                                                   federal lands   Indian lands    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

[[Page 16210]]

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 foreign-
based 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 for-profit 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.

[[Page 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 self-
determination, and seeks to continuously improve its communications and 
government-to-government 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

[[Page 16212]]

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
    <bullet> 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 well-completion 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

[[Page 16213]]

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:
    <bullet> Identifies the owner of the withheld information and 
provides the name, address and contact information for an authorized 
representative of the owner;
    <bullet> Identifies the Federal statute or regulation that would 
prohibit the BLM from publicly disclosing the information if it were in 
the BLM's possession;
    <bullet> 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;
    <bullet> Affirms that the information is not publicly available;
    <bullet> 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);
    <bullet> 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;
    <bullet> 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
    <bullet> 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

[[Page 16214]]

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.

[[Page 16215]]

    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 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. 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 
machine-readable 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.

[[Page 16216]]

    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
----------------------------------------------------------------------------------------------------------------
                                                                                                  D. (column B x
                               A.                                       B.              C.           column C)
Total hours                                                              Type of       Number of       Hours per
                                                                        response       responses        response
----------------------------------------------------------------------------------------------------------------
Request for Prior Approval of Hydraulic Fracturing Job Using an            2,614               8          20,912
 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.............................................
Request for Prior Approval of Hydraulic Fracturing Job Using a               200               8           1,600
 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..............................
Sundry Notices and Reports on Wells/Hydraulic Fracturing/Request              84               8             672
 for Approval of Remedial Plan 43 CFR 3162.3-3(e)(3) Form 3160-5
Sundry Notices and Reports on Wells/Hydraulic Fracturing/                  2,814               8          22,512
 Subsequent Report Sundry Notice 43 CFR 3162.3-3(g) and (i) Form
 3160-5.........................................................
Affidavit in Support of Claim of Confidentiality 43 CFR 3162.3-            2,814               1           2,814
 3(j)...........................................................
Sundry Notices and Reports on Wells/Hydraulic Fracturing/                    281               8           2,248
 Variance Request 43 CFR 3162.3-3 Form 3160-5...................
                                                                 -----------------------------------------------
    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 Re-Enter. 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 non-hour 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

[[Page 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 lands-mineral 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

0
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


Sec.  3160.0-3  [Amended]

0
2. In Sec.  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),''.

0
3. Amend Sec.  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:


Sec.  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:

[[Page 16218]]

    (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

0
4. Amend Sec.  3162.3-2 by revising the first sentence of paragraph (a) 
and revising paragraph (b) to read as follows:


Sec.  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).
* * * * *

0
5. Revise Sec.  3162.3-3 to read as follows:


Sec.  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,     The operator must comply
 2015.                                       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    To conduct hydraulic
 before June 24, 2015, but the authorized    fracturing within 90 days
 drilling operations did not begin until     after the effective date of
 after June 24, 2015.                        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     The operator must comply
 completed before September 22, 2015.        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 one-half 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 quarter-quarter 
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;

[[Page 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.

[[Page 16220]]

    (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 Sec.  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 BLM-designated 
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

[[Page 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.

[[Page 16222]]


0
6. Amend Sec.  3162.5-2 by revising the first sentence of paragraph (d) 
to read as follows:


Sec.  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