Oil and Gas; Hydraulic Fracturing on Federal and Indian Lands

Federal RegisterMar 26, 2015

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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.

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,

October 2009,” commonly known as HF1, to provide guidance and highlight industry recommended practices for well construction and integrity for those wells that will be hydraulically fractured. The purpose of the guidance was to ensure protection of shallow groundwater aquifers and the environment while enabling economically viable development of oil and natural gas resources. More recently, regulations from states, such as Colorado and Wyoming, and professional papers, such as King, George, SPE 152596, (Feb. 2012), focused on the estimation, analyses, and control of risks from hydraulic fracturing operations. All of these factors have led to, and informed, this rulemaking. To ensure that these standards adequately address emerging technological developments and health and environmental protections, the BLM will evaluate the adequacy of this rulemaking 7 years after the date of publication.

Pursuant to the Federal Land Policy and Management Act (FLPMA), Indian mineral leasing laws, and other statutes, the BLM is charged with administering oil and gas operations in a manner that protects Federal and Indian lands while allowing for appropriate development of the resource. The BLM oversees approximately 700 million subsurface acres of Federal mineral estate and carries out some of the regulatory duties of the Secretary of the Interior for an additional 56 million acres of Indian mineral estate across the United States. Currently, nearly 36 million acres of Federal land are under lease for potential oil and gas development in 33 states. As of June 30, 2014, there were approximately 47,000 active oil and gas leases on public lands, and approximately 95,000 oil and gas wells. Like other BLM regulations, this final rule applies to oil and gas operations on public lands (which include split estate lands,

i.e.,

lands where the surface is owned by an entity other than the United States), as well as operations on Indian lands, to ensure that these lands and communities all receive the same level of protection as provided on public lands.

Oil and gas leasing decisions on public lands are made through a thorough, deliberative, and transparent process rooted in Resource Management Plans (RMPs) that cover virtually all BLM-administered public land and related mineral estate. Oil and gas decisions contained within BLM RMPs also apply to lands where the surface is privately owned, but the mineral estate is in Federal ownership. The BLM establishes, amends, and revises RMPs as required by the FLPMA with involvement by the community and stakeholders. As part of the land use planning process, the BLM engages the public in a variety of ways and conducts environmental reviews as required by the National Environmental Policy Act (NEPA), and other applicable natural and cultural resource protection authorities. While the public makes known to the BLM which lands they are interested in leasing, prior to leasing any lands, the BLM undertakes the appropriate NEPA review and provides an opportunity for the public to review and comment on the analyses and documents that the agency prepares.

Existing Requirements

Relevant existing requirements for oil and gas operations are set out at 43 CFR 3162.3-1 and Onshore Oil and Gas Orders 1, 2 and 7. Most of these requirements have been in place for at least 25 years. This final rule will supplement the existing requirements, which will remain in place. On either Federal leaseholds, or Indian lands, an operator may not begin operations until it has filed an Application for a Permit to Drill (APD) with the BLM and received approval from the BLM to commence operations. Existing Federal law requires the BLM to post notices of APDs for oil and gas development on public lands for public inspection for 30 days, during which time the public may express any concerns to the BLM's authorized officer as the agency conducts a site-specific environmental analysis of the proposed well site proposal. Those concerns and other issues identified earlier in the process, or during site examinations, may result in conditions of approval (COA) on the operator's drilling permit that require, forbid, or control specified activities or disturbances. Examples of COAs include providing for road improvements and erosion control measures, or applying seasonal restrictions on some activities. In addition, baseline water testing is a best management practice that the BLM encourages. The BLM may require water testing and monitoring, particularly if water quality impacts are a significant concern based on local conditions, and where the BLM or a cooperating landowner or manager manages the surface estate where testing could yield useful water quality information. This is consistent with what several states, including California, Colorado, and Wyoming, are already doing. The BLM does not post for public inspection notices of APDs for Indian oil and gas leases or agreements because there is no requirement in the Indian leasing statutes similar to that in Section 17 of the Mineral Leasing Act.

Under Onshore Oil and Gas Order 1, Approval of Operations, the location of the well must be identified and important aspects of the proposed operations described. Onshore Order 2 requires all usable water zones to be protected by steel casing and cement, and requires the casing, once in place, to be pressure tested. Casing and cement must meet specific design criteria, which BLM engineers verify as part of the permit review process. When a well is no longer capable of producing, Onshore Order 2 mandates minimum standards for the placement, quality, and verification of cement plugs to ensure that any remaining oil and gas cannot migrate into usable water zones. BLM inspectors witness aspects of drilling and plugging operations to ensure that the operator is in compliance with Onshore Order 2 and the permit to drill.

New Requirements

With this rule, the BLM establishes new requirements to ensure wellbore integrity, protect water quality, and enhance public disclosure of chemicals and other details of hydraulic fracturing operations. The rule requires an operator planning to conduct hydraulic fracturing to do the following:

• Submit detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, the depths of all usable water, estimated volume of fluid to be used, and estimated direction and length of fractures, to the BLM with the APD or a Sundry Notice and Report on Wells (Form 3160-5) as a Notice of Intent (NOI) to hydraulically fracture an existing well;

• Design and implement a casing and cementing program that follows best practices and meets performance standards to protect and isolate usable water, defined generally as those waters containing less than 10,000 parts per million of total dissolved solids (TDS);

• Monitor cementing operations during well construction;

• Take remedial action if there are indications of inadequate cementing, and demonstrate to the BLM that the remedial action was successful;

• Perform a successful mechanical integrity test (MIT) prior to the hydraulic fracturing operation;

• Monitor annulus pressure during a hydraulic fracturing operation;

• Manage recovered fluids in rigid enclosed, covered or netted and screened above-ground storage tanks, with very limited exceptions that must be approved on a case-by-case basis;

• Disclose the chemicals used to the BLM and the public, with limited exceptions for material demonstrated through affidavit to be trade secrets;

• Provide documentation of all of the above actions to the BLM.

Specifically, this final rule will add to existing requirements by providing information to the BLM and the public on the location, geology, water resources, location of other wells or fracture zones in the area, and fracturing plans for the operation before the well is permitted. To ensure well integrity, the final rule will require specified best practice performance standards for all wells, including cement return and pressure testing for surface casing, cement evaluation logs for intermediate and production casing, and remediation plans and cement evaluation logs for any surface casing that does not meet performance standards.

The final rule eliminates the use of “type wells” in demonstrating well integrity, and requires that specified best practices be used and demonstrated for all wells, not just a sample well. For surface casing, the final rule does not require a cement evaluation log (CEL) for each well, substituting other equally or more protective performance standards, including cement returns and pressure testing. For any surface casing not meeting these performance standards, an approved remedial plan and CEL will be required. For intermediate and production casing not cemented to the surface, a CEL will be required for all wells.

The final rule will require interim storage of all produced water in rigid enclosed, covered, or netted and screened above-ground tanks, subject to very limited exceptions in which lined pits could be used.

Public disclosure of all chemicals, subject to limited exceptions for trade secret material, will be required after fracturing operations are complete. The existing database, FracFocus (

http://fracfocus.org

), can be used for this disclosure.

FracFocus is managed by the Ground Water Protection Council (GWPC), a non-profit organization of state water quality regulatory agencies, and by the Interstate Oil and Gas Compact Commission (IOGCC), a multi-state government agency charged with balancing oil and gas development with environmental protection. The BLM will continue to work with FracFocus in coordination with the U.S. Department of Energy (DOE) to ensure that the recommendations of the Secretary of Energy's Advisory Board for improvement of the database are made.

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

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:

Secretary of Energy's Advisory Board recommendations can be downloaded from

http://energy.gov/seab/downloads/fracfocus-20-task-force-report.

http://www.gwpc.org/major-improvements-fracfocus-announced.

• Reducing the number of human errors in disclosures

• Expanding the public's ability to search records

• Providing public extraction of data in a “machine readable” format and

• Updating educational information on chemical use, oil and gas production, and potential environmental impacts.

As a part of the MOU with GWPC, FracFocus will automatically notify the BLM when an operator uploads chemical disclosure information about a Federal or Indian well. The BLM will obtain the information from FracFocus and keep those records in compliance with all pertinent record management requirements.

The BLM developed this final rule with the intention of improving public awareness and strengthening oversight of hydraulic fracturing operations without introducing unnecessary new procedures or delays in the process of developing oil and gas resources on public and Indian lands. Some states, including Alaska, Arkansas, Colorado, Illinois, Michigan, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, Utah, and Wyoming have regulations in place addressing hydraulic fracturing operations. Operators with leases on Federal lands must comply with both the BLM's regulations and with state operating requirements, including state permitting and notice requirements to the extent they do not conflict with BLM regulations. To address concerns from states and tribes about possible duplicative efforts, the final rule provides that in situations in which specific state or tribal regulations are demonstrated to be equal to or more protective than the BLM's rules, the state or tribe may obtain a variance. Such a variance will allow for enforcement of the more protective state or tribal rule.

For many years, the BLM has maintained a number of agreements with certain states and tribes concerning implementation of the various regulatory programs in logical and effective ways. The BLM will work with states and tribes to establish formal agreements that will capitalize on the strengths of partnerships, and reduce duplication of effort for agencies and operators, particularly by implementing the final rule as consistently as possible with state or tribal regulations.

The provisions in this final rule provide for the BLM's consistent oversight and establish a baseline for environmental protection across all public and Indian lands undergoing hydraulic fracturing. The BLM has analyzed the costs and the benefits of this proposed action in an accompanying Regulatory Impact Analysis available in the rulemaking docket. The BLM estimates that the rule will impact about 2,800 hydraulic fracturing operations per year, but that it could impact up to 3,800 operations per year based on previous levels of activity on Federal lands and growing activity on Indian lands. The BLM estimates that the compliance cost will be about $11,400 per well, or about $32 million per year. On average this equates to approximately 0.13 to 0.21 percent of the cost of drilling a well.

Many of the requirements generally are consistent with industry guidance, the voluntary practice of operators, and some are required by state regulations. So to the extent that industry is already in compliance, the cost of several of the provisions may be overestimated. The improvements also provide significant benefits to all Americans by avoiding potential damages to water quality, the environment, and public health. The rule creates a consistent, predictable, regulatory framework, in accordance with the BLM's stewardship responsibilities for hydraulic fracturing under the FLPMA and the Indian mineral leasing statutes.

I. Background

II. Discussion of the Final Rule and Comments on the Proposed Rules

III. Procedural Matters

I. Background

Well stimulation techniques, such as hydraulic fracturing, are commonly used by oil and natural gas producers to increase the volumes of oil and natural gas that can be extracted from wells. Hydraulic fracturing techniques are particularly effective in enhancing oil and gas production from shale gas or oil formations. Until quite recently, shale formations rarely produced oil or gas in commercial quantities because shale does not generally allow the flow of hydrocarbons to wellbores unless

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

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,

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:

See updated FracFocus link:

http://www.fracfocus.org/welcome

States currently using FracFocus

States proposing to use FracFocus

1 Alabama

1 Alaska.

2 California

2 Florida.

3 Colorado

3 Kentucky.

4 Illinois

4 Nevada.

5 Kansas

6 Louisiana

7 Michigan

8 Minnesota

9 Mississippi

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.

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.

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

incorporated city, are closed to leasing by law. In addition to public scoping, the BLM coordinates with state, county, and local governments, Indian tribes, and other Federal agencies.

Once various land use options have been developed the BLM generally analyzes the environmental impacts of the alternatives through an Environmental Impact Statement (EIS), which offers additional opportunity for public involvement. For proposed land use decisions, such as keeping areas open for oil and gas leasing, environmental impacts are assessed based on a Reasonable Foreseeable Development (RFD) Scenario that projects the estimated levels and types of industry activity and the associated surface disturbance that might occur during the life of the RMP. Because the RMP and EIS generally cover all the Federal land and mineral estate administered by a BLM field office, the impact analysis is typically done on a broad scale. Mitigation measures developed through the draft RMP and EIS process can be implemented as stipulations on oil and gas leases. In addition to compliance with the National Environmental Policy Act (NEPA), the BLM must comply with the National Historic Preservation Act and the Endangered Species Act (ESA) and engage in a consultation process with the U.S. Fish and Wildlife Service under the ESA, if threatened or endangered species or critical habitat may be affected.

Once a draft RMP and EIS are developed, the public has an additional opportunity to review and comment on the analysis and proposed mitigation measures in the EIS. When all comments have been considered, the BLM develops a final RMP and EIS. The Record of Decision finalizes the RMP, selecting a final action to be adopted from a reasonable range of alternatives and explaining the rationale for the decision. Once the Record of Decision is signed, the BLM makes all land use decisions, including oil and gas development decisions, in accordance with the RMP.

Leasing Process.

The next step in the oil and gas development process is the designation of parcels to be offered for lease, and an additional environmental review. Under existing regulations, the public may nominate tracts of land that they would like to see leased. It is far more common, however, for members of the industry to express interest in an area being offered for lease. The BLM first must ensure that the proposed tracts are under Federal jurisdiction and are open to leasing in accordance with the RMP. The next step is to conduct a second NEPA review—typically through an Environmental Assessment (EA)—to address potential impacts that could be caused by oil and gas development within the nominated area. The NEPA review conducted at the leasing stage “tiers” from the RMP EIS. In other words, the issues, analysis of potential impacts, mitigation measures, and decisions in the RMP EIS are carried through to the NEPA review conducted at the leasing stage.

An interdisciplinary team consisting of resource specialists develops the NEPA documentation. The interdisciplinary team visits the site to gather on-the-ground data on potential impacts and mitigation measures. After the site visit, an EA is drafted, including coordination with county, state, and Federal agencies, and consultation with Indian tribes, if applicable, in the area proposed for leasing. EAs are posted on the BLM Web site and are available in the public room(s) at BLM field offices for public review and comment, typically for a 30-day period. The BLM reviews and addresses comments received during that 30-day period when it finalizes the EA. Specific mitigation measures are developed in the context of the NEPA review and are included in a notice to potential bidders of an oil and gas lease at a lease sale. If the environmental review concludes with a finding that the proposed lease issuance would result in no significant impacts to the quality of the human environment (FONSI), then the lease parcel can be included in the next scheduled lease sale without any further NEPA analysis. Upon issuance by the BLM, the lease allows the operator to conduct operations on the lease.

Exploration and development requirements.

The BLM has existing regulations, including Onshore Oil and Gas Orders, to ensure that operators conduct oil and gas exploration and development in an environmentally responsible manner that protects other resources. These requirements will remain in place and will be supplemented by this final rule.

Existing section 43 CFR 3162.3-1 and Onshore Order 1 require an operator to get approval from the BLM prior to drilling a well. The operator must submit an APD containing all of the information required by Onshore Order 1. This includes a completed Form 3160-3, Application for Permit to Drill or Re-Enter, a well plat, a drilling plan, a surface use plan, bonding information, and an operator certification.

Upon receiving a drilling proposal on Federal lands, the BLM is required by existing section 3162.3-1(g) to post information for public inspection for at least 30 days before action to approve the APD. The information must include: The company/operator name; the well name/number; and the well location described to the nearest quarter-quarter section (40 acres), or similar land description in the case of lands described by metes and bounds, or maps showing the affected lands and the location of all tracts to be leased and of all leases already issued in the general area. Where the inclusion of maps in such posting is not practicable, the BLM provides maps of the affected lands available to the public for review. The public posting is in the office of the BLM authorized officer and in the appropriate surface managing agency office, if other than the BLM. Some field offices also make this information available on the field office Web site. The public may review the posted information and provide any input they would like the BLM to consider during its environmental analysis. If the public has questions and concerns regarding drilling proposals, they can meet with BLM staff and share those concerns.

The drilling plan is a critical, detailed, and multi-faceted component of the APD that allows BLM engineers and geologists to complete an appraisal of the technical adequacy of, and environmental effects associated with, the proposed project. The drilling plan must include:

• Geological information, including the name and estimated tops of all geologic groups, formations, members, and zones as well as the estimated depths and thickness of formations, members, or zones potentially containing usable water, oil, gas, or prospectively valuable deposits of other minerals that the operator expects to encounter, and their plans for protecting such resources.

• Minimum specifications for blowout prevention equipment that will be used to keep control of well pressures encountered while drilling.

• A description of the proposed casing program, including the size, grade, weight, and setting depth of each casing string.

• Detailed information regarding the proposed cementing program, including the amount and types of cement the operator will use for each casing string, which is critical in establishing a barrier outside the casing between any hydrocarbon bearing zones and usable water zones. BLM engineers evaluate the proposed cementing program to ensure that the volume and strength of the cement is adequate to achieve the desired protections.

• Information regarding the proposed drilling fluid and proposed testing, logging, and coring procedures.

• 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.

• Other information that may be pertinent, including the directional drilling plan for deviated or horizontal wells so that BLM engineers can look for potential issues with existing wells.

Just as the drilling plan allows the BLM to ensure the down-hole technical adequacy of the proposed project, the surface use plan provides the BLM with information needed to ensure safe operations, adequate protection of the surface resources, groundwater, and other environmental components in areas where the BLM manages the surface.

The surface managing agency must approve surface use plans where the BLM does not manage the surface. The Bureau of Indian Affairs is considered to be the surface management agency for Indian lands. In the surface use plan, operators must also describe any Best Management Practices (BMPs) they expect to use. BMPs are mitigation measures applied to oil and natural gas drilling and production to help ensure that operators conduct energy development in an environmentally responsible manner. BMPs can protect water, wildlife, air quality, and landscapes. The BLM encourages operators to incorporate BMPs into their plans. Information concerning BMPs is available on the BLM's Web site at:

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices.html

Where the BLM manages the surface, the operator's surface use plan should incorporate the BLM's “Surface Operating Standards and Guidelines for Oil and Gas Exploration and Development,” which is commonly referred to as “The Gold Book.” The BLM developed “The Gold Book” to assist operators by providing information on obtaining permit approval and conducting environmentally responsible oil and gas operations. It is available on the BLM's Web site at:

http://www.blm.gov/wo/st/en/prog/energy/oil_and_gas/best_management_practices/gold_book.html

In general, the surface use plan must include the following:

• Location and description of, as well as maintenance plan for, existing and new roads the operator plans to use to access the proposed well.

• A map showing all known wells, regardless of their status (producing, abandoned, etc.) within a one-mile radius of the proposed location so that the BLM can ensure the proposal does not conflict with any current surface use. The BLM also uses this well information to identify any potential downhole conflicts or issues between the existing wells and the proposed well.

• A map or diagram showing the location of all production facilities and lines the operator will install if the well is successful (a producing well), as well as any existing facilities.

• Information concerning the water supply, such as rivers, creeks, springs, lakes, ponds, and wells that the operator plans to use for drilling the well.

• A written description of the methods and locations it proposes for safe containment and disposal of each type of waste materials that result from drilling the proposed well. The narrative must include plans for the eventual disposal of drilling fluids and any produced oil or water recovered during testing operations.

• A diagram in the surface use plan of the proposed well site layout.

• A plan for the surface reclamation or stabilization of all disturbed areas.

Another component of the APD is proof of adequate bond coverage as required by existing 43 CFR 3104.1 for Federal lands and 25 CFR 211.24, 212.24, and 225.30, for Indian lands. These regulations require the operator or the lessee to have an adequate bond in place prior to the BLM's approval of the APD. If the BLM determines that the current bond amount is not sufficient, the BLM can require additional bond coverage. The BLM determines the need for bond increases by considering the operator's history of violations, the location and depth of wells, the total number of wells involved, the age and production capability of the field, and any unique environmental issues.

Upon receipt of a complete APD, the BLM will schedule an onsite inspection with the operator so that the BLM and operator may further identify 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.

Compliance with Onshore Oil and Gas Order No. 2.

Upon BLM's approval of an APD, the operator may commence drilling of the well. In addition to the approved plan and the conditions of approval, the operator must also comply with the requirements of Onshore Oil and Gas Order No. 2, (Onshore Order 2), which details the BLM's uniform national standards for the minimum levels of performance expected from operators when conducting drilling operations on Federal and Indian lands. Many of the requirements of Onshore Order 2 ensure the protection of usable water.

Onshore Order 2 also requires the operator to:

• Conduct the proposed casing and cementing programs as approved to protect and isolate all usable water zones, lost circulation zones, abnormally pressured zones, and any prospectively valuable deposits of minerals. It also requires the operator to report all indications of usable water.

• Employ technical measures to center the casing in the drilled hole prior to cementing in order to ensure wellbore integrity. It also requires the operator to cement the surface casing up to the surface either during the primary cement job or by remedial cementing, which ensures that all usable water zones behind the surface casing are isolated and protected.

• Wait until the cement for all casing strings achieves a minimum of 500 pounds per square inch (psi) compressive strength at the casing shoe prior to drilling out the casing shoe and utilize proper cementing techniques.

• Pressure test the casing prior to drilling out the casing shoe to ensure the integrity of the casing. The operator must also conduct a pressure integrity test of each casing shoe on all exploratory wells, and on that portion of any well approved for a 5,000 psi blowout preventer. The pressure test ensures the integrity of the cement around the casing shoe.

In addition, Onshore Order 2 identifies the minimum requirements for blowout prevention equipment and the minimum standards for testing the equipment. Proper sizing, installation, and testing of the blowout prevention equipment ensures that the operator maintains control of the well during the drilling process, which is necessary for protection of usable water zones.

Post-Approval Inspections and Reporting.

The BLM conducts inspections of drilling operations to ensure that operators comply with the Onshore Order 2 drilling regulations, the approved permit, and the conditions of approval. The BLM drilling inspections consist of two general types of inspections: Technical and environmental. The BLM petroleum engineering technicians conduct technical inspections of the drilling operations such as witnessing the running and cementing of the casing, witnessing the testing of the blowout prevention equipment, and detailed drilling rig inspections. Such inspections also include review of documentation such as the third-party cementing job ticket that describes the cementing operation, including the type and amount of cement used, the cement pump pressures, and the observation of cement returns to the surface, if applicable.

The BLM natural resource specialists conduct environmental inspections of drilling operations that focus primarily on the surface use portion of the approved drilling permit. This includes inspection of the access road, the well pad, and pits. While the BLM does not have the budget or personnel to inspect every drilling operation on Federal and Indian minerals, the BLM conducts inspections in accordance with an annual risk-based strategy to ensure compliance with the regulations, lease stipulations, and permits.

Within 30 days after the operator completes a well, the operator is required by existing regulations to submit a BLM Well Completion or Recompletion Report and Log (Form 3160-4), which provides drilling and completion information. Similar to completion of a new well, an existing well can be recompleted to restore productivity and thus produce oil or gas which would have otherwise been abandoned. This document includes the actual casing setting depths and the amount of cement the operator used in the well, together with information regarding the completion interval between, for example, the top and bottom of the formation, the perforated interval, and the number and size of perforation holes. The operator is also required to submit copies of all electric and mechanical logs. The BLM reviews this information to ensure that the operator set the casing and pumped the cement according to the approved permit.

Compliance with Onshore Oil and Gas Order No. 7.

Once a well goes into production, water is often produced with the oil and gas. The water tends to be of poor quality and is not generally suitable for drinking, livestock, or other uses and, therefore, must be disposed of properly. Onshore Oil and Gas Order No. 7 (Onshore Order 7) regulates the disposal of produced water. Under Onshore Order 7, operators must apply to the BLM for authorization to dispose of produced water by injecting the water back into a suitable formation, by storing it in pits, or by other methods approved by the BLM. If the water will be stored in pits, the BLM requires specific design standards to ensure the water does not contaminate the environment or pose a threat to public health and safety.

Post-Drilling Inspections.

After a well has been drilled and completed, the BLM continues to inspect the well until it has been plugged and abandoned, and the surface has been rehabilitated. During the production phase of the well, the BLM inspections focus on two primary issues: Production and the environment. The Federal Government (Federal leases) or an Indian tribe or individual Indian allottee (Indian leases) receive a royalty on the oil and gas removed or sold from the lease based on the volume, quality, and value of the oil and gas. Royalties from Federal leases are shared with the state as provided by statute. Production inspections are conducted by the BLM to ensure the volume and quality of the oil and gas is accurately measured and properly reported. Environmental inspections are conducted by the BLM to ensure that wellpads and facilities are in compliance with regulations, Onshore Orders, and approved permits. Environmental inspections include ensuring that pits are properly constructed, maintained, and protected from wildlife; identifying leaking wells or pipelines; ensuring that the wellsite and facilities are properly maintained; and ensuring that proper erosion controls and rehabilitation measures are in place.

Well Plugging, Abandonment and Site Restoration.

When a well has reached the end of its economic life, Federal regulations require that it be plugged and abandoned to prevent oil and gas from leaking to the surface or contaminating water bearing zones or other mineral zones. An operator may request well abandonment or the BLM may require it. In either case, the operator must submit a proposal for well plugging, including the length, location, type of cement, and placement method to be used for each plug. The operator must also submit a plan to rehabilitate the surface once the well has been plugged. The goal of surface rehabilitation is to remove obvious visual evidence of the pad and to promote the long-term stability of the site and vegetation.

The BLM inspects both well plugging and surface restoration. Well plugging inspections are completed to ensure the plugs are set in accordance with the

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

This final rule makes a series of changes to the definitions section. The term “master hydraulic fracturing plan” is added. The definition of a cement evaluation log is moved from § 3162.2-3(e)(2) to the definitions section. The term “confining zone” is now defined because that term is used in revised § 3162.3-3(d). The term “refracturing” is deleted from this section and the rest of the rule. The term “usable water” is updated to remove the requirement to identify usable water only via drill log. The final rule also clarifies the definition of “usable water”.

43 CFR 3162.3-2 Subsequent Well Operations

Paragraph (a) of this section is modified slightly by removing the phrase “the operator” because it is redundant.

43 CFR 3162.3-3(a) Hydraulic Fracturing

43 CFR 3162.3-3(a) Subsequent Well Operations; Hydraulic Fracturing

The final rule clarifies the application of this rule to wells at various stages of completion on the publication and effective date, and clarifies what sections of the rule apply based on a table which distinguishes leases with approved APDs from leases without approved APDs, as well as leases with approved APDs that do not have wells spudded.

43 CFR 3162.3-3(b) Isolation of Usable Water to Prevent Contamination

The term “refracturing” is deleted.

43 CFR 3162.3-3(c) When an Operator Must Submit Notification for Approval of Hydraulic Fracturing

43 CFR 3162.3-3(c) How an Operator Must Submit a Request for Approval of Hydraulic Fracturing

Paragraphs (c)(1) and (2) of this section are revised non-substantively and for clarity. Paragraph (c)(3) is revised to remove references to refracturing. As in the supplemental proposed rule, the operator may submit the hydraulic fracturing proposal either in the APD or as an NOI. The final rule removes “type wells” from this section. In the final rule a request to hydraulically fracture can be submitted for a group of wells in a master hydraulic fracturing plan. Paragraph (c)(4) is added to address and clarify when an operator must submit a new NOI.

43 CFR 3162.3-3(d) What the Notice of Intent Sundry Must Include

43 CFR 3162.3-3(d) What a Request for Approval of Hydraulic Fracturing Must Include

Consistent with other changes in this rule, the final rule replaces the procedure for submitting an NOI for multiple wells through a type well submission, and instead allows submission of a master hydraulic fracturing plan. Paragraph (d)(1) is revised to require specific information regarding wellbore geology, including information regarding the formation into which hydraulic fracturing fluids are to be injected, the estimated depths of the confining zones and occurrences of usable water. Paragraph (d)(2) is revised to require a map showing information regarding known or suspected faults and fractures. Paragraph (d)(4) is also revised to require submission of a map showing information about the trajectory of the wellbore and estimated direction and length of the fractures that will be propagated and all existing wellbore trajectories for all wells within one-half mile of the wellbore that will be hydraulically fractured.

43 CFR 3162.3-3(d)(2)

The final rule deletes the requirement to submit occurrences of usable water by use of a drill log and instead allows flexibility in how to obtain the information.

43 CFR 3162.3-3(d)(3)

The final rule eliminates the requirement to submit the proposed measured depth of perforations or the open hole interval and estimated pump pressures and makes it clear that the wells referred to in this provision are water supply wells.

43 CFR 3162.3-3(d)(4)

The final rule combines paragraphs (ii) and (iii) into a revised paragraph (ii) to read “the maximum anticipated surface pressure that will be applied during the hydraulic fracturing process.” The revised terminology encompasses the intent of the previous two paragraphs. Supplemental proposed rule paragraph (iv) is now paragraph (iii) and is revised in the final rule, and the word “calculated” is deleted, to reinforce the lack of certainty of the information in the APD or NOI at this stage of operations. Supplemental proposed rule paragraph (v) is deleted and replaced with a revised paragraph (iv), which seeks the estimated minimum vertical distance to the nearest usable water aquifer above the fracture zone. New paragraph (v) asks for the measured depth of the proposed perforated or open hole interval. Both the old paragraph (v) and the new paragraph (iv) aim to provide guidance to the BLM on protecting usable water zones.

43 CFR 3162.3-3(d)(5)

The final rule eliminates some of the specific details of the fluid recovery plan, focusing on estimated volume, proposed handling methods and proposed disposal methods. Further, the timeline is being clarified to better reflect the scope of the plan. This paragraph is also revised by adding a provision asking for information about the handling of recovered fluids between the time of the start of hydraulic fracturing operations and the approval of the disposal of produced fluids under BLM's regulations, which are currently contained in existing Onshore Order 7. Paragraph (i) is revised by eliminating the three circumstances that were listed where the volume of recovered fluid must be estimated, but keeping the requirement to estimate the volume of fluid to be recovered. New paragraph (ii) asks for the proposed methods of handling recovered fluids by cross reference to paragraph (h) of this section, which requires the use of rigid enclosed, covered or netted and screened above-ground tanks to store these fluids (with a limited exception for the use of lined pits). Paragraph (iii) of this section is revised by making clear the methods of handling recovered fluids that must be described in the application.

None

43 CFR 3162.3-3(d)(6)

The final rule includes a requirement for a surface use plan of operations if the hydraulic fracturing operation would cause additional surface disturbance. By reference to paragraph (e), it requires documentation that an adequate cement job occurred for all casing strings designed to isolate usable water.

43 CFR 3162.3-3(d)(6)

43 CFR 3162.3-3(d)(7)

Because of new paragraph (d)(6), the former paragraph (d)(6) is renumbered as paragraph (d)(7), and is revised to make it clear that the requirement may apply to an APD as well as a NOI.

43 CFR 3162.3(e) Monitoring of Cementing Operations and Cement Evaluation Log Prior to Hydraulic Fracturing

43 CFR 3162.3-3(e) Monitoring and Verification of Cementing Operations Prior to Hydraulic Fracturing

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

43 CFR 3162.3-3(e)(1)

This paragraph is revised to make it clear that the information request is for any casing string used to isolate usable water zones. The section is also revised to require that the information be submitted to the authorized officer 48 hours prior to the start of hydraulic fracturing operations unless the authorized officer approves a shorter time.

43 CFR 3162.3-3(e)(2)

New paragraph (e)(2) replaces supplemental proposed rule paragraph (e)(2) and requires that prior to hydraulic fracturing operations the operator must determine and document that there is adequate cement for all casing strings to isolate usable water. For surface casing, the operator must observe cement returns to the surface and document any indications of inadequate cement following the new requirements of this paragraph. For intermediate or production casing, if the casing is not cemented to the surface, the operator must run a CEL demonstrating that there is at least 200 feet of adequately bonded cement protecting the deepest usable water zone. If the casing is cemented to the surface, then the operator must follow the same requirements as for surface casing established earlier in this section.

43 CFR 3162.3-3(e)(3), (e)(4), and (e)(5)

43 CFR 3162.3-3(e)(3)

Final paragraph (3) combines revised supplemental proposed rule paragraphs (3), (4), and (5). For any well where there is an indication of inadequate cement, the operator must follow the provisions of this paragraph. The operator must notify the BLM of the inadequate cement within 24 hours of discovering it (paragraph (3)(i)) and submit a plan to the BLM requesting approval of remedial action to achieve adequate cement (paragraph (3)(ii)). This section also addresses emergency situations where an operator may request oral approval of remedial action to correct inadequate cement. Such oral approvals must be followed by written notice within 5 business days following oral approval. The operator must also verify that the remedial action was successful with a CEL or other method BLM approves in advance (paragraph (3)(iii)). Consistent with the supplemental proposed rule, the operator must submit a subsequent report for the remedial action including a certification that the remedial action followed the approved plan and was successful (paragraph (3)(iv)). Under paragraph (3)(v), the operator must submit to the BLM the results of the CEL or other testing method that showed that the remedial action was successful at least 72 hours before starting hydraulic fracturing operations.

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

Paragraph (1) of this section is revised to include the words “that will be applied during the hydraulic fracturing process,” to clarify the timing of the requirement. Paragraph (2) of this section is revised by replacing the word “treating” with the word “surface” in the second sentence of this paragraph.

43 CFR 3162.3-3(g) Monitoring and Recording During Hydraulic Fracturing

This paragraph has been revised to delete the term “refracturing,” and clarifies the actions that operators must take when pressure within the annulus increases by more than 500 pounds per square inch as compared to the pressure immediately preceding the stimulation.

43 CFR 3162.3-3(h)

43 CFR 3162.3-3(h) Management of Recovered Fluids

This section has undergone numerous changes. The final rule requires that fluids recovered be stored in above-ground tanks prior to disposal under BLM's regulations (currently in Onshore Order 7). Paragraphs (1) and (2) specify the very limited conditions under which an authorized officer may approve a lined pit in lieu of a tank.

43 CFR 3162.3-3(i) Information that Must be Provided to the Authorized Officer After Completed Operations

43 CFR 3162.3-3(i) and (i)(1) Information that Must be Provided to the Authorized Officer After Hydraulic Fracturing is Completed

The heading of this section is revised to make it clearer. Paragraph (i)(1) of this section is also revised to require the operator to provide information about each additive in the hydraulic fracturing fluid. This will help to account for proppants as well as chemical additives.

43 CFR 3162.3-3(i)(2)

43 CFR 3162.3-3(i)(2), (i)(3), and (i)(5)

This section has been revised to seek only the actual sources and locations of the water used in the hydraulic fracturing fluid. The pressure information requested in the supplemental proposed rule is covered in the final rule by paragraph (3) and the depth of perforations and open hole interval is part of new paragraph (5).

43 CFR 3162.3-3(i)(3)

The final rule seeks the maximum surface pressure rather than the actual surface pressure and no longer seeks the flush rate or the final pump pressure concentration in the fracturing fluid.

43 CFR 3162.3-3(i)(4)

This section requires the report to include the actual, estimated, or calculated fracture length, height, and direction. This section remains as proposed.

None

43 CFR 3162.3-3(i)(5)

New paragraph (5) requires information previously contained in paragraph (2), regarding the actual measured depth of perforations or the open-hole interval.

None

43 CFR 3162.3-3(i)(6)

New paragraph (6) requires operators to report the total volume of fluid recovered between the time that hydraulic fracturing is completed and when the operator starts to report water produced from the well to Office of Natural Resources Revenue (ONRR).

43 CFR 3162.3-3(i)(5)(i)

43 CFR 3162.3-3(i)(7)

The final rule revises this renumbered paragraph to clearly outline the timeframe for reporting information pertaining to fluid recovery.

43 CFR 3162.3-3(i)(5)(ii)

43 CFR 3162.3-3(i)(7)(i)

This final section is renumbered, but is similar to the supplemental proposed rule.

43 CFR 3162.3-3(i)(5)(iii)

43 CFR 3162.3-3(i)(7)(ii)

The final rule would simplify this section by removing the reference to Onshore Order No. 7 and seek information on disposal method, such as injection, recycling, or off-lease storage.

43 CFR 3162.3-3(i)(6)

Deleted

This section is deleted and is unnecessary because the Authorized Officer can always require an explanation of any deviation under (i)(10) of this section.

43 CFR 3162.3-3(i)(7)

43 CFR 3162.3-3(i)(8)

The final rule renumbers this section. Paragraphs (8)(ii) and (8)(iii) are revised to make it clear that the provisions only apply to hydraulic fracturing fluid constituents once they arrive on the lease.

43 CFR 3162.3-3(i)(8)

43 CFR 3162.3-3(i)(9)

The final rule renumbers this section. The well logs and records of adequate cement bonds, including the cement monitoring report and any cement evaluation log, are no longer required to be submitted under this section because this information is covered either in the APD or NOI under paragraph (e) of this section.

43 CFR 3162.3-3(j) Identifying Information Claimed to be Exempt from Public Disclosure

The final rule at paragraph (j)(1) strengthens the affidavit provisions to ensure that operators fully describe and attest to the basis for their claim of exemption from public disclosure for trade secrets. The affidavit must be signed by a corporate officer or the equivalent responsible official of the operator. The affidavit must identify and provide contact information for the owner of the withheld information, if it is not the operator. New paragraph (j)(2) provides that if the operator relies on facts supplied by another entity, it must include an affidavit from a responsible official of that entity verifying those facts. Former paragraph (j)(2) has been renumbered (j)(3) without substantive change. Former paragraph (j)(4) has been renumbered as paragraph (j)(5) and is revised by requiring that the operator maintain records of the information claimed to be exempt from disclosure until the later of the BLM's approval of a final abandonment notice, or 6 years from completion of hydraulic fracturing operations for Indian lands, or 7 years from completion of hydraulic fracturing operations for Federal lands, as is consistent with applicable law. Any subsequent operator is responsible for maintaining access to those records. The final rule also adds a new paragraph (j)(6) to this section requiring the operator to submit the chemical family name or other similar descriptor for information claimed to be exempt from disclosure.

43 CFR 3162.3-3(k) Requesting a Variance from the Requirements of this Section

The final rule revises the variance provisions to allow for individual variances and state/tribal variances in different sections. Most of the substantive information in this section has not changed, but has been re-organized and revised for clarity. One revision to this section is made to make the rule consistent with Onshore Order 1 by clarifying that the decision on whether to approve a variance request is not administratively appealable to either the State Director or to the Interior Board of Land Appeals under 43 CFR part 4.

Section-by-Section Discussion of the Revised Proposed Rule and Discussion of Comments

Comments Addressed in This Rule

In this preamble, the BLM discusses many of the comments received on the supplemental and proposed rules. Commenters provided detailed and helpful information that assisted in framing the issues and ultimately in producing this final rule. The Department does not address every comment in this final rule, because the changes in this rule have mooted some comments on the initial proposed rule and the supplemental proposed rule. Other comments were not central to the evaluation the BLM has undertaken, and thus discussion of those few comments would not contribute to the public's understanding of the reasons for the final rule.

Additionally, not every change in the final rule responds to a specific comment. Some revisions clarify the final rule, and still other revisions allow this final rule to be more effective or reduce inefficiencies.

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

substantially modify the requirements in Onshore Order 2, although it clarifies the term by incorporating specific inclusions and exclusions as to what constitutes usable water. The final rule keeps the 10,000 ppm threshold from Onshore Order 2 as the primary determining factor for what constitutes usable water.

Because of the inconsistency between the supplemental proposed rule and existing codified regulations, some commenters were under the impression that this rule was increasing the level of protection for usable water from 5,000 ppm to 10,000 ppm, while other commenters believed that this rule was proposing to decrease the level of protection from 10,000 ppm to 5,000 ppm. Neither impression is true. This rule maintains the 10,000 ppm standard that has been in place since 1988. The BLM still believes that a 10,000 ppm threshold is appropriate because it is consistent with the threshold used as part of the definition of “underground sources of drinking water” in EPA regulations implementing the Safe Drinking Water Act (SDWA). The SDWA was enacted in 1974 and is the primary Federal law that ensures the quality of American's drinking water (

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

). Specific comments that were based on the erroneous assumption that the BLM was changing the TDS threshold for usable water are summarized as follows. No changes to the final rule were made as a result of these comments.

• Numerous comments expressed concern that the requirement to protect usable water (section 3162.5-2) as defined would result in significantly increased costs because protecting water with TDS levels up to 10,000 ppm would require running casing and cement much deeper than it is currently run. Because the definition of usable water has not substantially changed in this rule, there will be no significant changes in costs of running casing and cement.

• Many commenters thought that there was no use in protecting water zones with TDS levels greater than 5,000 ppm, because water with a TDS higher than 5,000 is not suitable for human, agricultural, or industrial uses. One comment stated that the BLM considers water with TDS levels greater than 5,000 ppm as hazardous to wildlife. This rule does not change the primary criteria for protecting usable water up to 10,000 ppm, which has been in place for the past 26 years. Given the increasing water scarcity and technological improvements in water treatment equipment, it is not unreasonable to assume aquifers with TDS levels above 5,000 ppm are usable now or will be usable in the future.

• Some commenters expressed a concern that the conflicting definitions in Onshore Order 2 and in this rule will cause confusion for operators. There is no conflict between the definition in this rule and the definition in Onshore Order 2. This rule clarifies the term and incorporates specific inclusions and exclusion as to what is deemed to be usable water.

Several comments stated that the cost of running surface casing and cement deep enough to protect all usable water zones, as defined, would significantly increase the cost of drilling wells. This is an erroneous concern. It is not uncommon for deeper usable water zones to be protected with intermediate or production casing, which is allowed under Onshore Order 2 and this rule. No changes to the final rule were made as a result of these comments.

Several commenters suggested changing the definition of usable water to exclude aquifers that are not economical or feasible to use. The commenters said that these would include aquifers that are too deep, too small, too remote, or are not capable of achieving some set flow rate. No changes to the rule were made as a result of these comments. From a practical standpoint, excluding aquifers based on depth, size, location, flow rate, or other characteristics would be difficult in a national rule for several reasons. For example, the depths to which a water user might drill would depend on such factors as the need for water, the availability of other supplies, and the hydrologic characteristics of the aquifer (natural pressures might raise water in a deep well closer to the surface). Excluding aquifers from protection based on some arbitrary flow rate would be impractical. Measuring the flow rate potential of an aquifer would be a time-consuming and expensive process for operators to perform and for the BLM to review. Just as with oil and gas wells, the flow rate potential of a water well can depend on the specific location, depth, and methodology used. Furthermore, a flow rate that is inadequate for one type of use might be adequate for another type of use. State and tribal agencies, and EPA under the SDWA, have the expertise and authority to consider all the factors in characterizing groundwater.

Several commenters questioned the basis for the 10,000 ppm of TDS in the definition. The 10,000 ppm of TDS used in Onshore Order 2 and this rule is based on part of the definition of “underground source of drinking water” in EPA's regulations implementing SDWA.

Another change made to this definition in response to comments involved three exemptions from the definition of usable water listed in the supplemental proposed rule. The proposed exclusions in paragraphs (2)(i), (2)(ii), and (2)(iii) of the definition have been modified for clarity and to better reflect the roles of EPA and states and tribes in managing groundwater resources.

The proposed exclusion in paragraph (A) of the definition, regarding hydrocarbon zones, was added to the supplemental proposed rule based on comments received on the initial proposal (77 FR 27691). Some commenters noted correctly that developing minerals from a zone that is also a USDW requires specific authorization under the SDWA. The BLM has edited the exclusion in former paragraph (A)

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.

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

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

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).

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

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

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.

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)

through (d)(7) to be included in an MHFP. Final section 3162.3-3(d)(4)(iii) requires the operator to submit a map showing the estimated fracture direction and length. Although the final rule does not require fracture modeling, it would fulfill the requirements of this section. No revisions to the rule are made as a result of these comments because the rule already allows fracture estimations or modeling to be applied to a group of wells under an MHFP.

Several commenters stated that the CEL for a type well should be applicable to wells that meet the criteria for group approval, but were submitted under a separate NOI. The BLM did not revise the rule as a result of these comments because the requirements to run CELs on type wells and submit the results of the CEL as part of the group approval package are eliminated in the final rule. Several comments suggested that for group hydraulic fracturing submissions, the operator should be required to certify that the cement, fracturing fluids, and drilling practices for all wells included in the submission comply with the information submitted in the MHFP. The BLM did not incorporate this suggestion into the final rule because a certification is not necessary to ensure compliance with the approved NOI for multiple wells, and because information related to well integrity is now required for each individual well. Any unapproved deviation from the approved NOI and MHFP would be considered a violation and would be enforced under existing subpart 3163, Noncompliance, Assessments, and Penalties. One comment said that the option to permit multiple wells will not help operators who do not drill wells in groups. In the final rule, MHFPs will primarily streamline the permitting process for operators who are hydraulic fracturing multiple wells within an area having similar geology. No revisions to the rule were made as a result of this comment. The fact that not every operator can take advantage of a provision of the rule designed to streamline the process does not make that provision undesirable or unnecessary.

Section 3162.3-3(d) Application for Hydraulic Fracturing

This section specifies that the application must include:

• Information about the geology and the formation, confining zones, usable water (depths estimated), faults and fractures, location of water supply, and transportation method. This information is generally consistent with the requirements in Onshore Order 1;

• Information about the proposed hydraulic fracturing operation, the volume of fluid to be used, the maximum anticipated surface pressure, wellbore trajectory, the estimated direction and length of fractures, and the locations, trajectories, and depths of existing wellbores within a half mile of the wellbore; and

• Information about how the operator will handle recovered fluids, the estimated volume of fluids to be recovered, and the proposed disposal method.

Operators planning to conduct hydraulic fracturing should already possess that information because hydraulic fracturing is a complex operation and would only be conducted pursuant to a plan for performance.

The final rule incorporated several revisions to this section. Requirements relating to an MHFP (referred to as a submission for a group of wells in the supplemental proposed rule) are moved from section (d) to section (c) because section (c) has to do with how to apply for hydraulic fracturing approval. A discussion of the MHFP is given in the definitions section and the response to comments on the type well in the proposed rule are addressed in the discussion of section (c).

Section 3162.3-3(d)(1) in the supplemental proposed rule would have required the operator to identify the geologic formation that would be hydraulically fractured, including measured depths of the top and bottom of the formation. The final rule requires that the operator identify both the measured depths and the true vertical depths of the formation to be hydraulically fractured (paragraph (d)(1)(i)). This section of the final rule also requires the operator to identify the measured and true vertical depths of the confining zone (paragraph (d)(1)(ii)).

The requirement to identify usable water zones is moved from paragraph (d)(2) in the supplemental proposed rule to final paragraph (d)(1)(iii), along with a new requirement to state the measured and true vertical depths of the top and bottom of all usable water zones. The requirement to identify occurrences of usable water with a drill log in the supplemental proposed rule is deleted in the final rule. The BLM determined that it is not always necessary or practical to require a drill log to identify usable water and that there is no reason to be prescriptive about how usable water is identified. The BLM made these changes for several reasons. First, the BLM believes that by grouping all informational requirements relating to wellbore geometry into a single section, the clarity of the regulation is improved. Second, the BLM added a requirement to identify the “true vertical depth” of tops and bottoms of all the geologic zones in order to ascertain the vertical separation between zones. Also, under the final rule, the operator is required to identify the confining zone that is capable of preventing fluid migration between the zone that will be hydraulically fractured and any usable water zones.

Section 3162.3-3(d)(2) is revised in the final rule to require the operator to submit a map showing any faults or fractures within one-half mile of the wellbore trajectory that may transect the confining zone. This will allow the BLM to identify and analyze during the permit review process any potential for hydraulic fracturing fluid to migrate outside of the zone being fractured.

Section 3162.3-3(d)(3) in the supplemental proposed rule is separated in the final rule to improve clarity. This section in the supplemental proposed rule contained requirements for 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.

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

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

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