PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 1. PRACTICE AND PROCEDURE

SUBCHAPTER I. PERMIT PROCESSING

16 TAC §1.201

The Railroad Commission of Texas (Commission) proposes amendments to §1.201, relating to Time Periods for Processing Applications and Issuing Permits Administratively. The Commission proposes the amendments to update cross-references to other Commission rules in the rule and in the table, as well as other nonsubstantive clarifications.

The Commission proposes amendments to §1.201(a) to more closely align with Government Code §2005.003, the statute which requires adoption of §1.201. The amendments clarify that §1.201 does not apply to all permits issued by the Commission, but only those permits for which the median time for processing a permit application from receipt of the initial application to the final permit decision exceeds seven days. The proposed amendments also replace the definition of "permit" with a reference to Government Code §2005.003 to ensure the Commission's rule is consistent with the statutory definition of the term.

The table in §1.201(a) is proposed to be amended to reflect current permits, operating division names, and permit processing time periods. Sections 3.8 (relating to Water Protection) and 3.57 (relating to Reclaiming Tank Bottoms, Other Hydrocarbon Wastes, and Other Waste Materials) are currently proposed to be amended in a separate Commission rulemaking. Thus, the obsolete sections of those rules and the permits issued pursuant to those rules are proposed to be removed from the table in §1.201(a). The amendments also correct other outdated references and remove permits the Commission no longer issues.

The Commission also proposes to restructure the table to limit the information for each permit to: (1) the permit and rule or law governing the permit; (2) the Commission division responsible for processing the permit; and (3) the initial and final review periods as required by Government Code §2005.003. The current table includes information on Commission forms and fees associated with the permits. However, form and fee information is more easily obtained from the Commission's website. The Commission's website is more frequently updated and allows more information about each permit to be accessible to persons seeking a permit from the Commission. The proposed amendments to the table also remove column names to simplify future updates. Column name references are proposed to be removed throughout the section and are replaced with general references to the table.

Several permit types are also proposed to be removed from the table because the permit processing time no longer exceeds seven days, the permit type is no longer issued, or the authorization does not meet the definition of a permit under Government Code §2005.003.

Finally, the Commission proposes amendments in §1.201(c)(7) and (e) to reflect the current name of the division which contains the Docket Services Section.

Paul Dubois, Assistant Director of the Oil and Gas Division and Director of Technical Permitting, has determined that for each year of the first five years the amendments will be in effect, there will be no fiscal implications for state or local governments as a result of the amendments. In addition, there is no anticipated cost for persons required to comply with the proposed amendments. The proposed amendments merely update §1.201 to provide current information regarding permit processing time periods at the Commission.

Mr. Dubois has determined that for each year of the first five years the proposed amendments will be in effect, the anticipated public benefit will be transparency regarding current Commission permit review time and related requirements.

The Commission has determined that the proposed amendments will not have an adverse economic effect on rural communities, small businesses, or micro-businesses. Therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis pursuant to Texas Government Code §2006.002.

The Commission has also determined that the proposed amendments will not affect a local economy. Therefore, the Commission has not prepared a local employment impact statement pursuant to Texas Government Code §2001.022.

The Commission has determined that the amendments do not meet the statutory definition of a major environmental rule as set forth in Texas Government Code, §2001.0225; therefore, a regulatory analysis conducted pursuant to that section is not required.

During the first five years that the amendments would be in effect, the proposed amendments would not: create or eliminate any employee positions; require an increase or decrease in future legislative appropriations; increase fees paid to the agency; create a new regulation; increase or decrease the number of individuals subject to the rule's applicability; expand, limit, or repeal an existing regulation; or affect the state's economy. The amendments merely update the rule to reflect current time periods for administrative review and approval of permits and other authorizations given by the Commission.

Comments on the proposed amendments may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/legal/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until noon (12:00 p.m.) on Monday, December 2, 2024. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's website more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Paul Dubois at (512) 463-6778. The status of Commission rulemakings in progress is available at https://rrc.texas.gov/general-counsel/rules/proposed-rules/. If you submit a comment and do not see the comment posted at this link within three business days of submittal, please call the Office of General Counsel at (512) 463-7149. The Commission has safeguards to prevent emailed comments from getting lost; however, your operating system's or email server's settings may delay or prevent receipt.

The Commission proposes the amendments under Texas Government Code §2005.003, which requires a state agency that issues permits to adopt procedural rules for processing permit applications and issuing permits; Texas Government Code §2001.004, which requires a state agency to adopt rules of practice stating the nature and requirements of all available formal and informal procedures; and Texas Natural Resources Code §81.051 and §81.052, which provide the Commission with jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission.

Statutory Authority: Texas Government Code §§2005.003 and 2001.004; Texas Natural Resources Code §§81.051 and 81.052.

Cross-reference to statute: Texas Government Code Chapters 2001 and 2005; Texas Natural Resources Code Chapter 81.

§1.201.Time Periods for Processing Applications and Issuing Permits Administratively.

(a) Applicability. This rule applies to permits issued administratively by the Commission through the operating divisions listed in Table 1 of this section and for which the median permit processing time exceeds seven days. These permits are listed in [the permits listed in Column A of] Table 1 of this section. For purposes of this rule, the term "permit" has the meaning assigned in Texas Government Code Chapter 2005. [includes any authorization issued administratively by the Commission, through the Oil and Gas Division, the Gas Services Division, the Surface Mining and Reclamation Division, or the Rail/LP-Gas/Pipeline Safety Division, and required by the Commission either to engage in or conduct a specific activity or to deviate from requirements, standards, or conditions in statutes or Commission rules and for which the median processing time exceeds seven days].

Figure: 16 TAC §1.201(a) (.pdf)

[Figure: 16 TAC §1.201(a)]

(b) Completeness. An application is complete when the division or section shown in [Column B of] Table 1 has determined that the application contains information addressing each application requirement of the regulatory program and all information necessary to initiate the final review by the division or section processing the application. For purposes of this section, certain applicants[, as shown in Column D of Table 1,] are required to have an approved organization report (Form P-5) on file with the Commission in order for an application to be complete.

(c) Time periods.

(1) The date a permit application is received under this section is the date the application reaches the designated division or section within a division as shown in [Column B of] Table 1.

(2) The division or section shown in [Column B of] Table 1 shall process permit applications in accordance with the time periods shown in [Columns F and G of] Table 1 for a particular permit. Time periods are counted on the basis of calendar days.

(3) The Initial Review Period, shown in [Column F of] Table 1, begins on the date the designated division or section receives the application and ends on the date the division or section gives written notice to the applicant indicating that either:

(A) the application is complete and accepted for filing; or

(B) the application is incomplete, as described in paragraph (4) of this subsection.

(4) If the division or section determines that an application is incomplete, the division or section shall notify the applicant in writing and shall describe the specific information required to complete the application. An applicant may make no more than two supplemental filings to complete an application. The Initial Review Period shall start again each time the division or section receives a supplemental filing relating to an incomplete application. After the second supplemental submission, if the application is complete, the division or section shall administratively rule on the application; if the application is still incomplete, the division or section shall administratively deny the application. The division or section specifically does not have the authority to accept or review any other additional supplemental submissions. The division or section shall notify the applicant in writing of the administrative decision and, in the case of an administrative denial, the applicant's right to request a hearing on the application as it stands. The applicant may withdraw the application.

(5) The Final Review Period, shown in [Column G of] Table 1, begins on the date the division or section makes a determination under paragraph (3)(A) of this subsection and ends on the date the permit is:

(A) administratively granted;

(B) administratively denied; or

(C) docketed as a contested case proceeding if the application is neither administratively granted nor administratively denied.

(6) An applicant whose application has been administratively denied may request a hearing by filing a written request for a hearing addressed to the division or section processing the application, within 30 days of the date the application is administratively denied.

(7) Within seven days of either docketing an application under paragraph (5)(C) of this subsection or receiving a written request for a hearing under paragraph (6) of this subsection, the division or section processing the application shall forward the file and any request for hearing, including any memoranda or notes explaining or describing the reasons for docketing or administrative denial, to the Docket Services Section of the Hearings Division, which [Office of General Counsel. The Office of General Counsel] shall process the application as prescribed in subsection (e) of this section.

(d) Complaint procedure.

(1) An applicant may complain directly to the Executive Director if a division or section does not process an application within the applicable time periods shown in [Columns F and G of] Table 1, and may request a timely resolution of any dispute arising from the claimed delay. All complaints shall be in writing and shall state the specific relief sought, which may include the full reimbursement of any [the] fee paid in that particular application process[, if any, as shown in Column E of Table 1]. As soon as possible after receiving a complaint, the Executive Director shall notify the appropriate division director of the complaint.

(2) Within 30 days of receipt of a complaint, the division director of the division or section processing the application that is the subject of the complaint shall submit to the Executive Director a written report of the facts relating to the processing of the application. The report shall include the division director's explanation of the reason or reasons the division or section did or did not exceed the established time periods. If the Executive Director does not agree that the division or section has violated the established periods or finds that good cause existed for the division or section to have exceeded the established periods, the Executive Director may deny the relief requested by the complaint.

(3) For purposes of this section, good cause for exceeding the established period means:

(A) the number of permit applications to be processed by the division or section exceeds by at least 15 percent the number of permit applications processed by that division or section in the same quarter of the previous calendar year;

(B) the division or section must rely on another public or private entity to process all or part of the permit application received by the agency, and the delay is caused by that entity; or

(C) other conditions exist that give the division or section good cause for exceeding the established period, including but not limited to circumstances such as personnel shortages, equipment outages, and other unanticipated events or emergencies.

(4) The Executive Director shall make the final decision and provide written notification of the decision to the applicant and the division or section within 60 days of receipt of the complaint.

(e) Hearings. If an application is docketed as a contested case proceeding, it is governed by the time periods in this chapter (relating to Practice and Procedure) once the application has been filed with the Docket Services Section of the Hearings Division [Office of General Counsel].

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on October 15, 2024.

TRD-202404851

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: December 1, 2024

For further information, please call: (512) 475-1295

16 TAC §§3.1, 3.5, 3.7, 3.12, 3.13, 3.16, 3.17, 3.32, 3.36, 3.73, 3.78, 3.81, 3.82

The Railroad Commission of Texas (Commission) proposes amendments to §§3.1, 3.5, 3.7, 3.12, 3.13, 3.16, 3.17, 3.32, 3.36, 3.73, 3.78, and 3.81 relating to Organization Report; Retention of Records; Notice Requirements; Application To Drill, Deepen, Reenter, or Plug Back; Strata To Be Sealed Off; Directional Survey Company Report; Casing, Cementing, Drilling, Well Control, and Completion Requirements; Log and Completion or Plugging Report; Pressure on Bradenhead; Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes; Oil, Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas; Pipeline Connection; Cancellation of Certificate of Compliance; Severance; Fees and Financial Security Requirements; and Brine Mining Injection Wells. The Commission also proposes new §3.82, relating to Brine Production Projects and Associated Brine Production Wells and Class V Spent Brine Return Injection Wells.

The Commission proposes the amendments and new rule to implement the provisions of Senate Bill (SB) 1186 (88th Legislature, Regular Session, 2023), relating to the regulation by the Commission of brine mining.

Deep brine aquifers in Texas contain substantial lithium and other valuable deposits, but an incomplete regulatory framework surrounding the brine mining industry presently inhibits the investment required to extract it. The Legislature passed SB 1186 to clarify and complete the Commission's jurisdiction over brine mining to enable this new industry to develop in Texas.

Under current law, the Commission has jurisdiction over brine mining, but to date, the only brine mining in Texas has involved injecting fluid to dissolve subsurface salt formations, then extracting the salts from the resulting artificial brines. The Commission has obtained primary enforcement authority ("primacy") for the Class III Underground Injection Control (UIC) program under the federal Safe Drinking Water Act from the United States Environmental Protection Agency (EPA) for such operations and is therefore authorized to issue permits for those brine mining injection wells.

The EPA regulates the mining of lithium from naturally occurring brines differently from how it regulates mining artificially created brines. The EPA requires wells that re-inject naturally occurring brines into the aquifer from which they were produced after the extraction of minerals ("spent brine return injection wells") to be permitted as Class V injection wells. While the Commission has jurisdiction over this type of brine mining under state law, it does not yet have primacy for the Class V UIC program from the EPA required to permit the spent brine return injection wells. Spent brine return injection wells currently are not subject to any specific regulations, but rather are subject to the federal UIC regulations that exist for all Class V wells.

SB 1186 added a definition of "brine mining" to Texas Water Code §27.036, to clarify the Commission's jurisdiction over both types of brine mining under state law. The bill also instructed the Commission to seek primacy from the EPA for Class V injection wells designed to inject spent brine into the same formation from which it was withdrawn after the extraction of minerals. Additionally, the bill clarified that the Commission's jurisdiction over brine mining includes the authority to regulate brine production wells and brine injection wells.

The amendments proposed in §§3.1, 3.5, 3.7, 3.12, 3.13, 3.16, 3.17, 3.32, 3.36, and 3.73 add references to brine resources and spent brine return injection wells as applicable or otherwise clarify requirements of those sections related to brine production and injection. The amendments proposed in §§3.1 and 3.36 also add references to geothermal resources. The amendments proposed in §3.78 add references to encompass brine resources and revise outdated language related to National Pollutant Elimination System (NPDES) permits and processing of checks.

The Commission proposes amendments to §3.81 to revise the title to Class III Brine Mining Injection Wells. The proposed amendments also clarify the definition of brine mining injection well for purposes of §3.81. That section addresses requirements for Class III injection wells used to inject fluid to dissolve subsurface salt formations and then extract the salts from the resulting artificial brines. SB 1186 did not impact the Commission's existing authority over Class III brine mining injection wells or any existing permits for such operations. The proposed amendments to the title will clarify that the requirements of §3.81 do not apply to brine production projects and associated injection wells, which are addressed in proposed new §3.82.

Proposed §3.82(a) describes the scope and purpose of the new rule. The proposed new rule contains regulations for brine production projects and the associated brine production wells for the extraction of elements, minerals, mineral ions, salts, or other useful substances, including, but not limited to, lithium, lithium ions, lithium chloride, halogens or halogen salts, from a subsurface formation but not including oil, gas, or any product of oil or gas, or fluid oil and gas waste. "Product of oil and gas" is defined by Natural Resources Code §85.001 and "fluid oil and gas waste" is defined by Natural Resources Code §122.001. Proposed subsection (a) also states that the section governs Class V spent brine return injection wells used in association with brine production projects for the reinjection of the spent brine. Proposed subsection (a)(2) - (6) contains other clarifications related to the scope of proposed §3.82 including that the section applies to all wells used for brine production or Class V spent brine return injection even if the well was not initially completed for that purpose; an operator of wells subject to §3.82 shall comply with all other applicable Commission rules and orders; and proposed §3.82 does not apply to Class III injection wells or to the injection of hazardous waste as defined under 40 Code of Federal Regulations (CFR) Part 261. Proposed subsection (a)(7) clarifies that the requirements contained in §3.82 apply statewide to brine production projects, regardless of the brine field from which the brine resources are produced and the spent brine reinjected. Proposed §3.82(d) establishes statewide field rules for brine production fields including assignment of acreage, well spacing, and density provisions to promote the regular development of brine resources in a manner that does not damage the reservoir. Section 3.82(d) also contains procedures for requesting exceptions to statewide spacing, density, or acreage provisions or for requesting special field rules. Proposed §3.82(a)(8) specifies that a Commission order or permit governs in the event §3.82 conflicts with a provision or term of the order or permit.

Proposed §3.82(b) contains the definitions for terms used within §3.82. Notable terms include brine, brine field, brine production project, brine production project area, brine production project permit, brine resource, Class V spent brine return injection well, and good faith claim. The proposed definition of "brine field" is a formation or the correlative depth interval designated in the field designation or rules that contains brine resources. The brine production project is a project the purpose of which is the extraction of brine resources from a brine field. The term includes brine production wells, Class V spent brine return injection wells, monitoring wells, brine flowlines, and any equipment associated with the project. The brine production project area is proposed to be defined as the surface extent of the land assigned to a brine production project, as indicated on the plat required by §3.82(e)(3)(N).

Proposed subsection (b) also contains definitions for terms commonly used in Underground Injection Control (UIC) programs such as underground source of drinking water, mechanical integrity, affected person, interested person, confining zone, and area of review. An affected person is a person who, as a result of activity sought to be permitted, has suffered, or faces a substantial risk of suffering, concrete or actual injury or economic damage other than as a member of the general public. A competitor is not an affected person unless it has suffered, or faces a substantial risk of suffering, actual harm to its interest in real property or waste of substantial recoverable substances. Area of review is proposed to be defined as the brine production project area plus a circumscribing area the width of which is one-quarter mile measured from the perimeter of the brine production project area.

Several terms in subsection (b) are proposed to ensure consistency with 40 Code of Federal Regulations §144.3 and §146.3, which contain federal definitions related to Class V UIC wells. Those terms include aquifer, containment, fault, fluid, formation, formation fluid, injection well, lithology, packer, plugging, plugging record, pressure, transmissive fault or fracture, well, well injection, and well plug.

The Commission proposes general requirements for brine production projects in §3.82(c). Brine production projects are required to be permitted in accordance with §3.82 before a person may construct or operate brine production wells or Class V spent brine return injection wells. Proposed §3.82(c)(2) specifies the persons authorized to sign applications and reports related to the brine production project. Proposed paragraph (c)(2)(A) - (C) contains requirements identical to those in §3.81 for Class III brine mining injection wells.

Proposed §3.82(c)(3) requires operators of all Class V spent brine return injection wells to re-inject spent brine into the brine field from which the brine was produced. In proposed subsection (c)(4), the Commission requires all brine production wells and Class V spent brine return injection wells be drilled and completed or recompleted, operated, maintained, and plugged in accordance with the requirements §3.82 and the brine production project permit.

Proposed subsection (c)(5) instructs the Commission to assign a lease number to the brine production project and requires that lease number to be used by the project operator on required forms and reports.

In proposed §3.82(c)(6) - (9), the Commission lists the other rules with which a brine production project shall comply. An applicant for a brine production project permit shall comply with Commission regulations in §§3.1, 3.5, 3.11, 3.12, 3.16, 3.17, 3.18, 3.19, 3.36, and 3.80. An applicant for a brine production project shall also comply with 3.13, 3.14, 3.15, 3.35, and 3.78, but the Commission proposes additional requirements specifically applicable to brine production projects in subsection (c)(7) - (9). Proposed §3.82(c)(7) requires that, in addition to the requirements of §3.13, all wells associated with a brine production project use casing and cement designed to withstand the anticipated pressurization and formation fluids that are capable of negatively impacting the integrity of casing and/or cement such that it presents a threat to underground sources of drinking water or oil, gas, or geothermal resources. Surface casing is required to be set at the depth determined by the Geologic Advisory Unit. Although generally the Commission accepts requests for alternative surface casing depths, such requests will not be considered for brine production projects.

Proposed §3.82(c)(8) states that the requirements of §§3.14, 3.15, and 3.35 apply to all wells associated with a brine production project, except that the well operators shall plug all wells associated with a brine production project and remove all wastes, storage vessels, and equipment from the site within one year of cessation of brine production project operations.

Proposed §3.82(c)(9) requires all operators of wells drilled and operated in association with a brine production project to comply with the requirements of §3.78 as the requirements are applicable to brine production projects, except that, prior to spudding, the operator shall provide financial security in an amount estimated to plug each well in the brine production project after cessation of brine production project operations. Also, proposed subsection (c)(9) states that for an operator of a brine production project who has satisfied its financial security requirements by filing a cash deposit, the Commission shall refund to the operator the amount estimated to plug each well following its plugging if the amount of the deposit remaining after the refund would be sufficient to plug all remaining wells in the brine production project.

Proposed §3.82 (c)(10) prohibits any person from knowingly making any false statement, representation, or certification in any application, report, record, or other document submitted or required to be maintained under §3.82 or under any permit issued pursuant to §3.82. Proposed subsection (c)(10) also prohibits any person from falsifying, tampering with, or knowingly rendering inaccurate any monitoring device or method required to be maintained under §3.82 or under any permit issued pursuant to that section.

Proposed subsection (d) contains statewide field rules for spacing, acreage, and density of brine production projects. The subsection also addresses the process for requesting an exception to the statewide rules or adopting field rules for a particular brine field. Regarding spacing requirements, proposed subsection (d)(1) requires that all brine production wells and Class V spent brine return injection wells be completed within the brine production project area, which is defined in proposed subsection (b) as the surface extent of the land assigned to a brine production project, as indicated on the plat required by subsection (e)(3)(N). Any well must also be located no less than one-half mile from the boundary of the brine production project area and no less than one-half mile from any interest within the brine production project area that is not participating in the project. Special field rules or an exception obtained pursuant to subsection (d)(4) may alter the spacing requirements. Proposed subsection (d)(2) contains the acreage and density requirements for brine production projects. An applicant for a brine production project permit shall designate and assign acreage within the applicable brine field to the brine production project. Proposed §3.82(e)(3) requires the applicant to designate the total number of acres included in the brine production project area as part of the permit application. The minimum amount of acreage that must be assigned is 1,280 acres per brine production well included in the brine production project, unless special field rules provide different well density requirements or the applicant obtains an exception pursuant to subsection (d)(4). The maximum amount of acreage that may be assigned to a brine production well is 5,120 acres, unless special field rules apply. This requirement is proposed in subsection (d)(2)(C).

Proposed §3.82(d)(2)(B) and (D) contain requirements for operators of brine production projects that elect to file a plat assigning acreage in the brine production project area to a brine production well. Operators are not required to assign acreage to an individual brine production well as long as the total number of acres assigned to the brine production project area divided by the total number of brine production wells equals or exceeds 1,280 acres. If the operator elects to file a plat assigning acreage to a brine production well, proposed subsection (d)(2)(D) requires that the two farthermost points of acreage assigned to the well not exceed 23,760 feet, and the acreage assigned shall include all productive portions of the wellbore. The maximum diagonal proposed in subsection (d)(2)(D) is intended to prevent acreage designation resulting in an irregular shape. The diagonal of 23,760 feet assumes the maximum 5,120 acres has been assigned to the well, creating an acreage assignment in the shape of a rectangle that is two miles wide and four miles long. For this acreage designation, 23,760 feet is the farthest diagonal between two points on opposite sides of the rectangle. Special field rules may alter the maximum diagonal.

Proposed §3.82(d)(2)(E) prohibits multiple assignment of the same acreage in a brine field to more than one brine production well. Proposed subsection (d)(2)(F) requires that acreage included in a brine production project area consist of acreage for which the operator has a good faith claim to produce brine resources. Non-contiguous acreage included in the same brine production project area may not be separated by greater than the minimum spacing distance for wells; however, an operator may obtain an exception to the contiguity requirements pursuant to paragraph (d)(4)(C).

Proposed §3.82(d)(3) contains the required procedure for requesting a brine field designation and special field rules. Prior to submitting a request for special field rules which depart from the statewide spacing, acreage, and density requirements proposed in subsection (d)(1) and (d)(2), a new brine field must be designated by the Commission pursuant to the procedure proposed in subsection (d)(3). Proposed subsection (d)(3)(A) contains the required components of a request for a new field designation.

In §3.82(d)(3)(B), the Commission proposes the procedure and requirements for temporary and permanent field rules that differ from the statewide field rules in proposed in subsection (d)(1) and (d)(2). The Commission will accept applications for temporary brine field rules after the first well has been completed in a brine field. The applicant shall furnish the Commission with a list of the names and addresses of all operators of wells within five miles of the brine discovery well so that notice may be provided prior to the hearing. At the hearing on the adoption of temporary brine field rules, the applicant bears the burden of establishing that each of the proposed temporary brine field rules is reasonably expected to protect freshwater resources, protect correlative rights, prevent waste of recoverable brine resources, and promote the production of additional brine resources in an orderly and efficient manner. Proposed subsection (d)(3)(B) states that any temporary brine field rules adopted after a hearing remain in effect until 18 months after adoption or until permanent brine field rules are adopted. As proposed in subsection (d)(3)(C), an operator of a brine production well in the brine field subject to temporary field rules may request a hearing to adopt permanent field rules after the temporary rules have been effective for at least 12 months. The adoption of permanent brine field rules requires a hearing held after notice to operators within five miles of the brine discovery well. If permanent field rules are not adopted, temporary field rules expire after 18 months and the statewide field requirements of §3.82 apply to operations within the applicable brine field.

Proposed §3.82(d)(4) contains the required procedure for an operator of a brine production project that seeks an exception to the spacing, density, or acreage requirements in subsection (d). An exception to these requirements may be granted after a public hearing held after notice to all persons described in proposed subsection (d)(4). Persons required to receive notice of a request for a spacing or density exception are specified in proposed subsection (d)(4)(B), and persons required to receive notice of a request for an exception to contiguity requirements are specified in proposed subsection (d)(4)(C). At the hearing on an exception, the applicant has the burden to establish an exception is necessary to prevent waste or protect correlative rights.

Proposed §3.82(e) contains the application requirements for a brine production project permit. Applications for a brine production project permit shall be submitted to the Director in compliance with proposed subsection (e). A brine production project permit application is similar to an application for an area permit, which is addressed in §3.46(k) of this title, relating to Fluid Injection into Productive Reservoirs. The applicant for a brine production project permit is not required to submit applications for individual production and injection well permits at the same time the applicant files the brine production project permit application. Rather, the applicant is required to submit the information required by proposed subsection (e)(3) and shall also submit an application for at least one injection well. Unless the permit states otherwise, the brine production project operator may operate additional brine production wells and Class V spent brine return injection wells as part of the brine production project after the brine production project permit is issued; however, the operator shall obtain permits for those wells prior to commencing operations. The requirements for obtaining a Class V spent brine return injection well permit are proposed in §3.82(e)(4).

Proposed subsection (e)(3) specifies the required contents of a brine production project permit application, including the estimated maximum number of brine production wells and Class V spent brine return injection wells that will be operated within the brine production project; the total number of acres included in the proposed brine production project area; the brine field from which the brine will be produced and spent brine reinjected; complete electric logs of representative brine production wells and the Class V spent brine return injection wells or complete electric logs of representative nearby wells; wellbore diagrams showing the completions that will be used for brine production wells and Class V spent brine return injection wells; information to characterize the brine field from which the brine will be produced and into which the spent brine will be reinjected; and information to characterize the proposed confining zone.

Proposed subsection (e)(3) also contains requirements for the permit application to include the proposed operating data; a letter from the Geologic Advisory Unit of the Oil and Gas Division of the Railroad Commission of Texas stating that the use of the brine field for the injection of spent brine will not endanger usable quality water or USDWs; and an accurate plat showing the entire extent of the area of review. Proposed subsection (e)(3)(M) contains the elements required to be included on the plat. For example, subsection (e)(3)(M)(ii) requires the plat to reflect the location, to the extent anticipated at the time of the application, of each well within the area of review that the applicant intends to use for the brine production project including each existing well that may be converted to brine production or Class V spent brine return injection, each well the applicant intends to drill for brine production, each well the applicant intends to drill for project monitoring, and each Class V spent brine return injection well.

In §3.82(e)(3)(N), the Commission proposes to require the applicant for a brine production project to provide an additional plat showing the outline of the brine production project area and the following: (1) the operators of tracts in the brine production project area and tracts within the area of review; (2) owners of all leases of record for tracts that have no designated operator in the brine production project area and within the area of review; (3) owners of record of unleased mineral interests within the brine field for tracts in the brine production project area and tracts within the area of review; and (4) surface owners of tracts in the brine production project area and within the area of review. The plat shall include a list of the names and addresses of all persons listed in subsection (e)(3)(N) or the applicant may list the names and addresses on a separate sheet attached to the plat. "Operator" is defined in proposed §3.82(b) as a person, acting for itself or as an agent for others and designated to the Commission as the one who has the primary responsibility for complying with its rules and regulations in any and all acts subject to the jurisdiction of the Commission. The applicant shall determine the names and addresses of the surface owners from the current county tax rolls or other reliable sources and shall identify the source of the list. The operators and other persons indicated on the plat are among the persons required to be notified of the permit application under proposed §3.82(f).

Additional contents required to be included in the permit are proposed in §3.82(e)(3)(O) through (e)(3)(T). Several of the provisions are modeled after existing Commission requirements for injection well permit applications. For example, proposed §3.82(e)(3)(P) requires a survey of information from the United States Geological Survey (USGS) regarding the locations of any historical seismic events within a circular area of 100 square miles centered around the proposed injection well location. This requirement is also found in §3.9 of this title (relating to Disposal Wells) and §3.46 of this title.

In proposed §3.82(e)(4), the Commission proposes requirements for Class V spent brine return injection well permits. An operator of a Class V spent brine return injection well shall file an application for an individual well permit prior to commencement of injection operations into any Class V spent brine return injection well within the brine production project area. The required contents of the application are proposed in §3.82(e)(4)(A) through (e)(4)(F).

In §3.82(e)(5), the Commission proposes to include criteria for exempted aquifers, and in proposed subsection (e)(6), the Commission requires all Class V spent brine return injection wells covered by a brine production project permit to be completed, operated, maintained, and plugged in accordance with the requirements of subsection (j) and the brine production project permit. Regarding exempted aquifers, the Commission adopts 40 CFR §144.7 and §146.4 by reference effective January 6, 2025, which is the anticipated effective date for the proposed new rule and amendments. The Commission will update this date upon adoption if necessary to reflect the actual effective date.

Proposed subsection (f) contains the notice requirements for a brine production project. Proposed §3.82(f)(1) requires a brine production project permit applicant to identify whether any portion of the area of review (AOR) encompasses an Environmental Justice (EJ) or Limited English-Speaking Household community using the most recent U.S. Census Bureau American Community Survey data. If the AOR includes an EJ or Limited English-Speaking Household community, the applicant shall conduct enhanced public outreach activities to these communities, including a public meeting. Other efforts to include EJ and Limited English-Speaking Household communities are required in proposed subsection (f)(1)(A) - (E).

An applicant for a brine production project permit is required to provide notice of its application to the persons identified in proposed subsection (f)(2). The first few categories of notice recipients match the persons identified on the plat required by proposed subsection (e)(3)(N). In addition, the applicant is required to notify the city clerk or other appropriate city official of a city for which any portion falls within the area of review, the county clerk of any county or counties for which any portion falls within the area of review, and any other person designated by the Director.

Proposed §3.82(f)(2)(B) requires the applicant to mail or deliver notice in a form approved by the Commission. Notice shall be provided after Commission staff determines the application is complete. In addition, the applicant is required to publish notice of the brine production project permit application in a form approved by the Commission in a newspaper of general circulation of any county or counties for which any portion falls within the area of review. The first notice shall be published at least 14 days before the protest deadline in the notice of application and the notice shall be published once each week for two consecutive weeks. The applicant shall file a publisher's affidavit or other evidence of publication with the permit application.

Proposed §3.82(f)(2)(C) specifies the information that the applicant must include in the notice. The required information includes a copy of the plat required by subsection (e)(3)(M) and a statement than an affected person may file a protest within 30 days of the date of the notice and an interested person may submit comments to the Commission within 30 days of the date of the notice.

Proposed §3.82(f)(2)(D) and (E) clarify the notice requirements for individual Class V spent brine return injection wells and brine production wells. Once an applicant complies with the notice required to obtain a brine production project permit and the permit has been issued, no notice shall be required when filing an application for an individual injection well permit for any Class V spent brine return injection well or brine production well covered by the brine production permit unless otherwise provided in the permit or unless the applicant requests an exception.

Proposed §3.82(f)(3) specifies that an affected person has 30 days to file a protest and an interested person has 30 days to submit written comments on the brine production project permit application. Proposed subsection (f)(4) outlines when the Commission will hold a hearing on the brine production project permit application. The Commission will hold a hearing when the Commission receives a written protest from an affected person within 30 days after notice of the application is given in accordance with subsection (f) of this section, when the Director denies the application and the operator requests a hearing within 30 days of the notice of administrative denial, when the Director issues the permit and the operator requests a hearing to contest certain permit conditions; or when the Director determines that a hearing is in the public interest. Notice of a hearing will be given at least 30 days before the hearing.

In proposed §3.82(g), the Commission outlines the process for review of brine production project permit applications, including procedures for determining whether the application is complete and notifying the applicant of any deficiencies in the application. The permit may be administratively approved by the Director if a hearing is not required to be held pursuant to proposed subsection (f)(4) and the applicant provides sufficient evidence to demonstrate that the brine production project will not endanger USDWs or human health or the environment.

Proposed subsection (g)(2) addresses amendments to a permit. If a permittee seeks to make changes to brine production project and the changes are substantial, such as changing the exterior boundaries of, or maximum number of wells authorized in, the brine production project area, then the changes cannot be made unless the permittee files an application to amend the permit. An application to amend is also required if the permittee seeks to alter permit conditions.

Proposed §3.82(h) addresses procedures for Commission action on a permit including modification, revocation and reissuance, and termination. Proposed paragraphs (h)(1) and (2) outline the changes that constitute cause for modification or revocation and reissuance compared to minor changes that can be made administratively. Proposed (h)(3) specifies the causes for Commission termination of a permit during its term or for denying a permit renewal application. The causes for termination include conditions such as the permittee fails to comply with any condition of the permit or §3.82; the permittee misrepresents a relevant fact; or the Commission determines that the permitted injection endangers human health or the environment.

Proposed §3.82(i) contains the standard permit conditions that will be included in a brine production project permit. In proposed §3.82(i)(1), the Commission requires a brine production project permittee to provide access to the project facilities and records to Commission staff members. Similarly, proposed §3.82(i)(2) states the Commission may make any tests on any well at any time necessary for regulation of wells under this section, and the operator of such wells shall comply with any directives of the Commission to make such tests in a proper manner.

Proposed subsections (i)(3) - (19) contain additional permit conditions on topics including maintenance of financial assurance; the permit term and requirement for the permit to be reviewed once every five years; permit transfers, renewals, and other actions; monitoring, records, and reporting; plugging; identification; and dikes or fire walls.

Proposed §3.82(j) contains additional standard permit conditions for Class V spent brine return injection wells. The permit conditions proposed in subsection (j) apply in addition to the conditions imposed in subsection (i). Importantly, the permit standards for Class V spent brine return injection wells prohibit operating a Class V spent brine return injection well in a manner that allows: (1) fluids to escape into USDWs from the brine field from which it was produced; (2) fluid to escape from the permitted brine field; or (3) the movement of fluids containing any contaminant into USDWs. If the permittee violates these conditions, the permittee is required to immediately cease injection operations.

Proposed subsection (j)(4) specifies drilling and construction requirements for Class V spent brine return injection wells. In addition to the casing and cementing requirements of §3.13, the operator of a Class V spent brine return injection well shall set and cement surface casing from at least 100 feet below the lowermost base of usable quality water to the surface, regardless of the total depth of the well; set and cement long string casing at a minimum from the top of the brine field to the surface, unless the Director approves an alternate completion for good cause; and determine the integrity of the cement by a cement bond log. For newly drilled wells, the operator shall drill a sufficient depth into the brine field to ensure that when the well is logged prior to setting the long string the operator will be able to identify the top of the brine field and verify that the fluid will be injected only into the brine field. The Commission shall be provided with an opportunity to witness the setting and cementing of casing and running of cement bond logs. Thus, the operator is required to notify the appropriate Commission district office at least 15 days in advance of these activities.

Proposed subsection (j)(4)(D) requires the operator of the Class V spent brine return injection well to provide to the Commission a descriptive report interpreting the results of logs and tests conducted to verify the depth to the top of the brine field, adequacy of cement behind the casing strings, and injectivity and fracture pressure of the brine field. The report shall be prepared by a knowledgeable log analyst and submitted to the Director. Proposed subsection (j)(4)(E) and (F) require a Class V spent brine return injection well to be equipped with tubing and packer set within 100 feet of the top of the brine field and a pressure observation valve on the tubing and for each annulus. Proposed subsection (j)(4)(G) prohibits injection operations in a new Class V spent brine return injection well until the Director receives and reviews the completion report.

Proposed subsection (j)(5) contains the minimum permit conditions relating to how the Class V spent brine return injection well must be operated. All Class V spent brine return injection shall be into the same brine field from which the brine was extracted by the brine production wells. All injection shall be through tubing set on a packer. The packer shall be set within 100 feet of the top of the permitted injection interval unless the Director approves an exception. Except during well stimulation, injection pressure at the wellhead shall not exceed the maximum pressure calculated to assure that the injection pressure does not initiate new fractures or propagate existing fractures in the brine field. In no case may the injection pressure initiate fractures in the confining zone or cause the escape of injection or formation fluids from the brine field.

Proposed subsection (j)(5)(D) requires the operator to fill the annulus between the tubing and long string casing with a corrosion inhibiting fluid. All injection wells shall maintain an annulus pressure sufficient to indicate mechanical integrity unless the Director determines that such requirement might harm the integrity of the well or endanger USDWs. The annulus pressure shall be monitored by a pressure chart or digital pressure gauge. The operator shall provide the Director with a written report and explanation of any change in annulus pressure that would indicate a leak or lack of mechanical integrity within 15 days of detecting the change in pressure. An annulus pressure change exceeding 10% is an example of a change that indicates a leak or lack of mechanical integrity.

Proposed subsection (j)(5)(E) requires the operator to notify the appropriate Commission district office at least 48 hours prior to the beginning of a workover or corrective maintenance operations that involve the removal of the tubing or well stimulation. The operator must conduct a mechanical integrity test on the well after the workover if the packer is unseated during the workover.

The permit condition proposed in subsection (j)(6) specifies that, if necessary to prevent movement of fluid into USDWs, corrective action will be required for all known wells in the area of review that penetrate the top of the brine field for which the operator cannot demonstrate proper completion, plugging, or abandonment.

Section 3.82(j)(7) addresses proposed requirements for mechanical integrity. A Class V spent brine return injection well may not be used if it lacks mechanical integrity. The operator shall demonstrate the mechanical integrity of a Class V spent brine return injection well to the satisfaction of the Director. Proposed subsection (j)(7)(A) - (E) contain requirements for demonstrating mechanical integrity, including internal and external mechanical integrity. The Director may approve an alternate method for demonstrating mechanical integrity if the administrator of the EPA also approves the method.

Proposed subsection (j)(7)(G) and (H) outline the required timing and notice for mechanical integrity testing. Subsection (j)(7)(I) states that the permittee is required to file a complete record of the test, including a copy of the pressure record, with the Commission within 30 days after the test.

Proposed subsection (j)(7)(J) specifies permit conditions relating to wells that fail to demonstrate mechanical integrity. If the permittee or the Director finds that the well fails to demonstrate mechanical integrity during a test, fails to maintain mechanical integrity during operation, or that a loss of mechanical integrity is suspected during operation, the permittee shall halt injection immediately. The Director may allow continued injection if the permittee can establish continued injection will not endanger USDWs. The permittee shall orally report the failure of mechanical integrity to the Director within 24 hours from the time the permittee becomes aware of the failure, and the permittee shall include an anticipated date for a mechanical integrity demonstration. In addition, all wells that fail to pass a mechanical integrity test shall be repaired or plugged and abandoned within 90 days of the failure date unless the Director extends the 90-day timeline for good cause. The well is to be shut-in immediately after failure to pass the mechanical integrity test and shall remain shut-in until it passes a mechanical integrity test or is plugged and abandoned. Within 15 days of a failure of mechanical integrity, a written plan to restore mechanical integrity shall be submitted to the Director. The plan must be approved by the Director. The permittee shall not resume injection until the well demonstrates mechanical integrity.

In §3.82(j)(8) the Commission proposes permit conditions for Class V spent brine return injection wells relating to required monitoring, record-keeping, and reporting. Proposed subsection (j)(8) contains requirements for how long monitoring information shall be retained, the contents of the monitoring records, and reports that shall be made to the Commission, including reports of noncompliance that may endanger USDWs, human health, or the environment. Proposed subsection (j)(9) requires the permittee to provide the Commission notice 48 hours before performing any workover or corrective maintenance operations that involve the unseating of the packer or well stimulation. Subsection (j)(10) specifies that the Commission may establish additional permit conditions for Class V spent brine return injection wells on a case-by-case basis.

Proposed §3.82(k) describes the consequences for violations of §3.82. Any well drilled or operated in violation of §3.82 without a permit shall be plugged. In addition, violations of the requirements of §3.82 may subject the operator to penalties and remedies specified in the Texas Water Code, Chapter 27, and the Natural Resources Code, Title 3. A brine production well in violation of §3.82 may have its certificate of compliance revoked in the manner provided in subsections §3.73(d) - (g), (i) - (k) of this title (relating to Pipeline Connection; Cancellation of Certification of Compliance; Severance).

Proposed §3.82(l) clarifies that administrative actions taken pursuant to the provisions of §3.82 are subject to review by the commissioners. Proposed §3.82(m) clarifies references to the Code of Federal Regulations (CFR) within §3.82 and states where the federal regulations are available for review.

Finally, in §3.82(n) the Commission clarifies the proposed effective date for the section. The Commission will seek primacy from the United States Environmental Protection Agency so that the Commission may administer the Class V UIC program for spent brine return injection wells. The regulations in §3.82 pertaining to Class V spent brine return injection wells become effective upon EPA approval of the Commission's program. Until then, an operator of a brine production project must obtain a permit from the EPA to operate a Class V spent brine return injection well. All other regulations proposed in §3.82 become effective as provided in the Administrative Procedure Act, in Section 2001.001 et seq. of the Texas Government Code. The Commission anticipates the effective date of the proposed new rule and amendments will be January 6, 2025.

Leslie Savage, Chief Geologist, has determined that for each year of the first five years the new rule and amendments as proposed will be in effect, there will be minimal fiscal implications to the Commission as a result of enforcing or administering the amendments. Any costs associated with the amendments would be due to minor programming to update online systems. There will be no fiscal effect on local government.

Ms. Savage has determined that for the first five years the proposed new rule and amendments are in effect, the primary public benefit will be clarity regarding jurisdiction over brine production wells and Class V spent brine return injection wells in compliance with SB 1186.

Ms. Savage has determined that for each year of the first five years that the new rule and amendments will be in effect, there will be no economic costs for persons required to comply as a result of adoption of the proposed new rule and amendments. The proposed new rule and amendments merely provide a regulatory scheme for operations related to brine resources as required by the Legislature. There are forms, financial security, and fee requirements imposed if a person engages in activities regulated by the Commission. However, the proposed new rule does not impose these costs - the requirements apply to any activity under the Commission's jurisdiction.

The Commission has determined that the proposed new rule and amendments will not have an adverse economic effect on rural communities, small businesses or micro businesses. As noted above, there is no anticipated additional cost for any person required to comply with the proposed new rule and amendments. Therefore, the Commission has not prepared the economic impact statement or the regulatory flexibility analysis pursuant to Texas Government Code §2006.002.

The Commission has also determined that the proposed new rule and amendments will not affect a local economy. Therefore, the Commission has not prepared a local employment impact statement pursuant to Texas Government Code §2001.022.

The Commission has determined that the proposed new rule and amendments do not meet the statutory definition of a major environmental rule as set forth in Texas Government Code, §2001.0225(a); therefore, a regulatory analysis conducted pursuant to that section is not required.

During the first five years that the proposed new rule and amendments would be in effect, the proposed new rule and amendments would not create or eliminate any employee positions or require an increase or decrease in future legislative appropriations. The Commission has determined that the new program can be implemented with current resources. The proposed new rule would create a new government program and regulations as required by SB 1186, expand existing regulations to encompass this new resource, and will positively impact the state's economy. The proposed new rule and amendments would increase the number of individuals subject to the Commission's rules. Prior to SB 1186 it was unclear which rules applied to brine production projects. Because SB 1186 provided the Commission with authority to oversee such projects, those who wish to engage in a brine production project are now subject to the new requirements. The proposed new rule and amendments may increase fees paid to the agency - the Commission may receive more applications for P-5 Organization Reports, drilling permits, injection wells, exceptions, and corresponding fees from operators engaging in the activities regulated under proposed new §3.82.

Comments on the new rule and proposed amendments may be submitted to Rules Coordinator, Office of General Counsel, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711-2967; online at www.rrc.texas.gov/general-counsel/rules/comment-form-for-proposed-rulemakings; or by electronic mail to rulescoordinator@rrc.texas.gov. The Commission will accept comments until 12:00 noon on Monday, December 2, 2024. The Commission finds that this comment period is reasonable because the proposal and an online comment form will be available on the Commission's website more than two weeks prior to Texas Register publication of the proposal, giving interested persons additional time to review, analyze, draft, and submit comments. The Commission cannot guarantee that comments submitted after the deadline will be considered. For further information, call Ms. Savage at (512) 463-7308. The status of Commission rulemakings in progress is available at www.rrc.texas.gov/general-counsel/rules/proposed-rules/. If you submit a comment and do not see the comment posted at this link within three business days of submittal, please call the Office of General Counsel at (512) 463-7149. The Commission has safeguards to prevent emailed comments from getting lost; however, your operating system's or email server's settings may delay or prevent receipt.

The Commission proposes the new rule and amendments pursuant to Senate Bill 1186 and Texas Water Code §27.036, which provide the Commission jurisdiction over brine mining and authorize the Commission to issue permits for brine production wells and injection wells used for brine mining, and also instruct the Commission to adopt rules necessary to administer and regulate brine mining; Texas Natural Resources Code §§81.051 and 81.052, which provide the Commission with jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission; Texas Natural Resources Code, Chapter 102, which gives the Commission the authority to establish pooled units for the purpose of avoiding the drilling of unnecessary wells, protecting correlative rights, or preventing waste; and Texas Natural Resources Code §§85.201 - 85.202, which require the Commission to adopt and enforce rules and orders for the conservation and prevention of waste of oil and gas, and specifically for drilling of wells.

Statutory authority: Texas Natural Resources Code §§81.051, 81.052, 85.201, 85.202 and Chapter 102; Texas Water Code §27.036.

Cross reference to statute: Texas Natural Resources Code Chapters 81, 85, and 102; Water Code Chapter 27.

§3.1.Organization Report; Retention of Records; Notice Requirements.

(a) Filing requirements.

(1) Except as provided under subsection (e) of this section, no organization, including any person, firm, partnership, joint stock association, corporation, or other organization, domestic or foreign, operating wholly or partially within this state, acting as principal or agent for another, for the purpose of performing operations within the jurisdiction of the Commission shall perform such operations without having on file with the Commission an approved organization report and financial security as required by Texas Natural Resources Code §§91.103 - 91.1091. Operations within the jurisdiction of the Commission include, but are not limited to, the following:

(A) drilling, operating, or producing any oil, gas, brine, geothermal resource, spent brine return injection, brine mining injection, fluid injection, or oil and gas waste disposal well;

(B) transporting, reclaiming, treating, processing, or refining crude oil, gas and products, brine resources, or geothermal resources and associated minerals;

(C) - (K) (No change.)

(2) - (10) (No change.)

(b) Record requirements. All entities who perform operations which are within the jurisdiction of the Commission shall keep books showing accurate records of the drilling, redrilling, or deepening of wells, the volumes of crude oil on hand at the end of each month, the volumes of oil, gas, brine, and geothermal resources produced and disposed of, together with records of such information on leases or property sold or transferred, and other information as required by Commission rules and regulations in connection with the performance of such operations, which books shall be kept open for the inspection of the Commission or its representatives, and shall report such information as required by the Commission to do so.

(c) - (d) (No change.)

(e) Issuance of permits to organizations without active organization reports.

(1) Notwithstanding contrary provisions of this section, the Commission or its delegate may issue a permit to an organization or individual that does not have an active organization report or does not ordinarily conduct [oil and gas] activities under the jurisdiction of the Commission when the issuance of such a permit is determined to be necessary to implement a compliance schedule, or to remedy circumstances or a violation of a Commission rule, order, license, permit, or certificate of compliance relating to safety or the prevention of pollution. For permits issued under this subsection, the Commission or its delegate may impose special conditions or terms not found in like permits issued pursuant to other Commission rules. Any organization or individual who requests such a permit shall file an organization report and any other required forms for record-keeping purposes only. The report or form shall contain all information ordinarily required to be submitted to the Commission or its delegate.

(2) This section shall not limit the Commission's authority to plug or to replug wells or to clean up pollution or unpermitted discharges of [oil and gas] waste under the jurisdiction of the Commission.

(f) - (g) (No change.)

(h) Pursuant to Texas Natural Resources Code, §91.706(b), if an operator uses or reports use of a well for production, injection, or disposal for which the operator's certificate of compliance has been canceled, the Commission or its delegate may refuse to renew the operator's organization report required by Texas Natural Resources Code, §91.142, until the operator pays the fee required by §3.78(b)(8) [§3.78(b)(9)] of this title (relating to Fees and Financial Security Requirements) and the Commission or its delegate issues the certificate of compliance required for that well.

§3.5.Application To Drill, Deepen, Reenter, or Plug Back.

(a) Requirements for spacing, density, and units. An application for a permit to drill, deepen, plug back, or reenter any oil well, gas well, brine production well, or geothermal resource well shall be made under the provisions of §§3.37, 3.38, 3.39, [and/or] 3.40, and/or 3.82 of this title (relating to Statewide Spacing Rule; Well Densities; Proration and Drilling Units: Contiguity of Acreage and Exception Thereto; [and ] Assignment of Acreage to Pooled Development and Proration Units; and Brine Production Projects and Associated Brine Production Wells and Class V Spent Brine Return Injection Wells) (Statewide Rules 37, 38, 39, [and] 40, and 82), or as an exception thereto, or under special rules governing any particular oil, gas, brine, or geothermal resource field or as an exception thereto and filed with the commission on a form approved by the commission. An application must be accompanied by any relevant information, form, or certification required by the Railroad Commission or a commission representative necessary to determine compliance with this rule and state law.

(b) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.

(1) Application--Request by an organization made either on the prescribed form or electronically pursuant to procedures for electronic filings adopted by the commission for a permit to drill, deepen, plug back, or reenter any oil well, gas well, brine production well, or geothermal resource well.

(2) - (3) (No change.)

(c) - (d) (No change.)

(e) Exploratory and specialty wells. An application for any exploratory well or cathodic protection well that penetrates the base of the fresh water strata, fluid injection well, injection water source well, disposal well, brine production well, brine solution mining well, spent brine return injection well, or underground hydrocarbon storage well shall be made and filed with the commission on a form approved by the commission. Operations for drilling, deepening, plugging back, or reentering shall not be commenced until the permit has been granted by the commission. For an exploratory well, an exception to filing such form prior to commencing operations may be obtained if an application for a core hole test is filed with the commission.

(f) - (h) (No change.)

§3.7.Strata To Be Sealed Off.

Whenever hydrocarbon, brine or geothermal resource fluids are encountered in any well drilled for oil, gas, brine, or geothermal resources in this state, such fluid shall be confined in its original stratum until it can be produced and utilized without waste. Each such stratum shall be adequately protected from infiltrating waters. Wells may be drilled deeper after encountering a stratum bearing such fluids if such drilling shall be prosecuted with diligence and any such fluids be confined in its stratum and protected as aforesaid upon completion of the well. The commission will require each such stratum to be cased off and protected, if in its discretion it shall be reasonably necessary and proper to do so.

§3.12.Directional Survey Company Report.

(a) For each well drilled for oil, gas, brine, or geothermal resources for which a directional survey report is required by rule, regulation, or order, the surveying company shall prepare and file the following information. The information shall be certified by the person having personal knowledge of the facts, by execution and dating of the data compiled:

(1) - (7) (No change.)

(b) (No change.)

§3.13.Casing, Cementing, Drilling, Well Control, and Completion Requirements.

(a) General. Operators shall comply with this section for any wells that will be spudded on or after January 1, 2014.

(1) (No change.)

(2) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise.

(A) - (C) (No change.)

(D) Productive zone--Any stratum known to contain oil, gas, brine, or geothermal resources in commercial quantities in the area.

(E) - (P) (No change.)

(3) - (5) (No change.)

(6) Well control.

(A) (No change.)

(B) Well control equipment.

(i) (No change.)

(ii) For wells in areas with hydrogen sulfide, the operator shall comply with §3.36 of this title (relating to Oil, Gas, Brine, or Geothermal Resource Operation in Hydrogen Sulfide Areas).

(iii) - (x) (No change.)

(C) - (G) (No change.)

(7) - (10) (No change.)

(b) - (d) (No change.)

§3.16.Log and Completion or Plugging Report.

(a) Definitions. The following words and terms, when used in this section, shall have the following meanings, unless the context clearly indicates otherwise:

(1) - (3) (No change.)

(4) Well--A well drilled for any purpose related to exploration for or production or storage of oil or gas or brine or geothermal resources, including a well drilled for injection of fluids to enhance hydrocarbon recovery, injection of spent brine return fluids, disposal of produced fluids, disposal of waste from exploration or production activity, or brine mining.

(b) - (e) (No change.)

§3.17.Pressure on Bradenhead.

(a) (No change.)

(b) Any well showing pressure on the Bradenhead, or leaking gas, oil, brine, or geothermal resource between the surface and the production or oil string shall be tested in the following manner. The well shall be killed and pump pressure applied through the tubing head. Should the pressure gauge on the Bradenhead reflect the applied pressure, the casing shall be condemned and a new production or oil string shall be run and cemented. This method shall be used when the origin of the pressure cannot be determined otherwise.

§3.32.Gas Well Gas and Casinghead Gas Shall Be Utilized for Legal Purposes.

(a) - (d) (No change.)

(e) Gas Releases to be Burned in a Flare.

(1) (No change.)

(2) Gas releases authorized under this section must be managed in accordance with the provisions of §3.36 of this title (relating to Oil, Gas, Brine, or Geothermal Resource Operation in Hydrogen Sulfide Areas) when applicable.

(3) - (4) (No change.)

(f) - (j) (No change.)

§3.36.Oil, Gas, Brine, or Geothermal Resource Operation in Hydrogen Sulfide Areas.

(a) Applicability. Each operator who conducts operations as described in paragraph (1) of this subsection shall be subject to this section and shall provide safeguards to protect the general public from the harmful effects of hydrogen sulfide. This section applies to both intentional and accidental releases of hydrogen sulfide.

(1) Operations including drilling, working over, producing, injecting, gathering, processing, transporting, and storage of hydrocarbon, brine, or geothermal fluids that are part of, or directly related to, field production, transportation, and handling of hydrocarbon, brine, or geothermal fluids that contain gas in the system which has hydrogen sulfide as a constituent of the gas, to the extent as specified in subsection (c) of this section, general provisions.

(2) (No change.)

(b) - (e) (No change.)

§3.73.Pipeline Connection; Cancellation of Certificate of Compliance; Severance.

(a) - (i) (No change.)

(j) Pursuant to Texas Natural Resources Code, §91.706(b), if an operator uses or reports use of a well for production, injection, or disposal for which the operator's certificate of compliance has been canceled, the Commission may refuse to renew the operator's organization report required by Texas Natural Resources Code, §91.142, until the operator pays the fee required pursuant to §3.78(b)(8) [§3.78(b)(9)] of this title (relating to Fees and Financial Security Requirements) and the Commission issues the certificate of compliance required for that well.

(k) (No change.)

§3.78.Fees and Financial Security Requirements.

(a) (No change.)

(b) Filing fees. The following filing fees are required to be paid to the Railroad Commission.

(1) - (7) (No change.)

[(8) With each application for a permit to discharge to surface water other than a permit for a discharge that meets national pollutant discharge elimination system (NPDES) requirements for agricultural or wildlife use, the applicant shall submit to the Commission a nonrefundable fee of $300.]

(8) [(9)] If a certificate of compliance for a well or a lease [an oil lease or gas well] has been canceled for violation of one or more Commission rules, the operator shall submit to the Commission a nonrefundable fee of $300 for each severance or seal order issued for the well or lease before the Commission may reissue the certificate pursuant to §3.58 of this title (relating to Certificate of Compliance and Transportation Authority; Operator Reports) (Statewide Rule 58).

(9) [(10)] With each application for issuance, renewal, or material amendment of an oil and gas waste hauler's permit, the applicant shall submit to the Commission a nonrefundable fee of $100.

(10) [(11)] With each Natural Gas Policy Act (15 United States Code §§3301-3432) application, the applicant shall submit to the Commission a nonrefundable fee of $150.

(11) [(12)] Hazardous waste generation fee. A person who generates hazardous oil and gas waste, as that term is defined in §3.98 of this title (relating to Standards for Management of Hazardous Oil and Gas Waste), shall pay to the Commission the fees specified in §3.98(z).

(12) [(13)] Inactive well extension fee.

(A) For each well identified by an operator in an application for a plugging extension based on the filing of an abeyance of plugging report on Commission Form W-3X, the operator must pay to the Commission a non-refundable fee of $100.

(B) For each well identified by an operator in an application for a plugging extension based on the filing of a fluid level or hydraulic pressure test that is not otherwise required to be filed by the Commission, the operator must pay to the Commission a non-refundable fee of $50.

(13) [(14)] Groundwater protection determination letters.

(A) With each individual request for a groundwater protection determination letter, the applicant shall submit to the Commission a nonrefundable fee of $100.

(B) With each individual application for an expedited letter of determination stating the total depth of surface casing required for a well in accordance with Texas Natural Resources Code, §91.0115(b), the applicant shall submit to the Commission a nonrefundable fee of $75, in addition to the fee required by subparagraph (A) of this paragraph.

(14) [(15)] An operator must make a check or money order for any of the aforementioned fees payable to the Railroad Commission of Texas. If the check accompanying an application is not honored upon presentment, the Commission or its delegate may suspend or revoke the permit issued on the basis of that application, the allowable assigned, the exception to a statewide rule granted on the basis of the application, the certificate of compliance reissued, or the Natural Gas Policy Act category determination made on the basis of the application.

(15) [(16)] If an operator submits a check that is not honored on presentment, the operator shall[, for a period of 24 months after the check was presented,] submit the payment [any payments] in the form of a credit card, cashier's check, or cash.

(c) - (l) (No change.)

(m) Effect of outstanding violations.

(1) Except as provided in paragraph (2) of this subsection, the Commission shall not accept an organization report or an application for a permit or approve a certificate of compliance for a well or a lease [an oil lease or gas well] submitted by an organization if:

(A) - (B) (No change.)

(2) - (3) (No change.)

(n) (No change.)

§3.81.Class III Brine Mining Injection Wells.

(a) Definitions. The following words and terms, when used in this section, shall have the following meanings unless, the context clearly indicates otherwise.

(1) - (2) (No change.)

(3) Brine mining injection well--A Class III UIC well used to inject fluid for the purpose of extracting brine by the solution of a subsurface salt formation. The term "brine mining injection well" does not include a well used to inject fluid for the purpose of leaching a cavern for the underground storage of hydrocarbons or the disposal of waste, or a well used to inject fluid for the purpose of extracting sulphur by the thermofluid mining process.

(4) - (11) (No change.)

(b) - (e) (No change.)

(f) Conditions applicable to all permits. The conditions specified in this subsection apply to all permits.

(1) - (17) (No change.)

(18) Plugging. Within one year after cessation of brine mining injection operations, the operator shall plug the well in accordance with §3.14(a) and (c) - (h) [(c)(h)] of this title (relating to Plugging) (Rule 14(a) and (c) - (h)). For good cause, the director may grant a reasonable extension of time in which to plug the well if the operator submits a proposal that describes actions or procedures to ensure that the well will not endanger fresh water during the period of the extension.

(g) - (l) (No change.)

§3.82.Brine Production Projects and Associated Brine Production Wells and Class V Spent Brine Return Injection Wells.

(a) Scope and purpose.

(1) This section contains the regulations for:

(A) brine production projects and the associated brine production wells for the extraction of elements, minerals, mineral ions, salts, or other useful substances, including, but not limited to, lithium, lithium ions, lithium chloride, halogens or halogen salts, from a subsurface formation but not including oil, gas, or any product of oil or gas, as defined by Section 85.001 of the Natural Resources Code, or fluid oil and gas waste, as defined by Section 122.001 of the Natural Resources Code; and

(B) Class V spent brine return injection wells used in association with brine production projects for the reinjection of the spent brine.

(2) This section applies regardless of whether the well was initially completed for the purpose of brine production or Class V spent brine return injection or was initially completed for another purpose and is converted for brine production or Class V spent brine return injection.

(3) The operator of a brine production project, including associated brine production wells and Class V spent brine return injection wells, shall comply with the requirements of this section as well as with all other applicable Commission rules and orders.

(4) Any pipelines, flowlines, storage, or any other brine containers at the brine production project shall be constructed, operated, and maintained such that they will not leak or cause an unauthorized discharge to surface or subsurface waters.

(5) This section does not apply to Class III brine mining injection wells regulated under §3.81 of this title (relating to Class III Brine Mining Injection Wells).

(6) This section does not apply to the injection of fluids that meet the definition of a hazardous waste under 40 CFR Part 261.

(7) Subsection (d) of this section establishes statewide field rules for brine production fields including assignment of acreage, well spacing, and density provisions to promote the regular development of brine resources in a manner that does not damage the reservoir.

(8) If a provision of this section conflicts with any provision or term of a Commission order or permit, the provision of such order or permit controls, provided that the provision satisfies the minimum requirements for EPA's Class V Underground Injection Control (UIC) program.

(b) Definitions. The following words and terms when used in this section shall have the following meanings, unless the context clearly indicates otherwise.

(1) Affected person--A person who, as a result of activity sought to be permitted, has suffered, or faces a substantial risk of suffering, concrete or actual injury or economic damage other than as a member of the general public. A competitor is not an affected person unless it has suffered, or faces a substantial risk of suffering, actual harm to its interest in real property or waste of substantial recoverable substances.

(2) Application--The Commission form for applying for a permit, including any additions, revisions or modifications to the forms, and any required attachments.

(3) Aquifer--A geological formation, group of formations, or part of a formation that is capable of yielding a significant amount of water to a well or spring.

(4) Area of review (AOR)--The brine production project area plus a circumscribing area the width of which is one-quarter mile measured from the perimeter of the brine production project area.

(5) Brine--Saline water, whether contained in or removed from an aquifer, which may contain brine resources or other naturally-occurring substances. The term does not include brine produced as an incident to the production of oil and gas.

(6) Brine field--A formation or the correlative depth interval designated in the field designation or rules that contains brine resources.

(7) Brine production project--A project the purpose of which is the extraction of brine resources from a brine field. The term includes brine production wells, Class V spent brine return injection wells, monitoring wells, brine flowlines, and any equipment associated with the project.

(8) Brine production project area--The surface extent of the land assigned to a brine production project, as indicated on the plat required by subsection (e)(3)(N) of this section.

(9) Brine production project permit--A permit authorizing a brine production project issued by the Commission pursuant to this section.

(10) Brine production well--A well drilled or recompleted for the exploration or production of brine resources that is part of a brine production project.

(11) Brine resource--Elements, minerals, salts, or other useful substances dissolved or entrained in brine, including, but not limited to, lithium, lithium ions, lithium chloride, halogens, or other halogen salts, but not including oil, gas, or any product of oil or gas.

(12) Casing--A pipe or tubing of appropriate material, of varying diameter and weight, lowered into a borehole during or after drilling to support the sides of the hole and prevent the walls from caving, to prevent loss of drilling mud into porous ground, or to prevent water, gas, or other fluid from entering or leaving the hole.

(13) Cementing--The operation whereby a cement slurry is pumped into a drilled hole and/or forced behind casing.

(14) Class V spent brine return injection well--A well into which brine produced by a brine production project is re-injected into the same brine field from which it was withdrawn after the brine resources have been extracted. The term does not include a Class I, II, III, IV, or VI UIC well.

(15) Code of Federal Regulations (CFR)--The codification of the general and permanent rules published in the Federal Register by the executive departments and agencies of the federal government.

(16) Commission--The Railroad Commission of Texas acting through a majority of the Commissioners or through a Commission employee to whom the Commissioners have delegated authority.

(17) Confining zone--A geological formation, group of formations, or part of a formation that is capable of limiting fluid movement above or below the brine field.

(18) Contaminant--Any physical, chemical, biological, or radiological substance or matter in water.

(19) Corrective action--Methods to assure that wells within the area of review do not serve as conduits for the movement of fluids from the brine field and into or between USDWs, including the use of corrosion resistant materials where appropriate.

(20) Director--The Director of the Oil and Gas Division of the Railroad Commission of Texas or the Director's delegate.

(21) Electric log--A density, sonic, or resistivity (except dip meter) log run over the entire wellbore.

(22) EPA--The United States Environmental Protection Agency.

(23) Exempted aquifer--An aquifer or its portion that meets the criteria in the definition of USDW but which has been exempted according to the procedures in 40 CFR §144.7.

(24) Fault--A surface or zone of rock fracture along which there has been displacement.

(25) Flow rate--The volume per time unit given to the flow of gases or other fluid substance which emerges from an orifice, pump, turbine or passes along a conduit or channel.

(26) Fluid--Any material or substance which flows or moves whether in a semisolid, liquid, sludge, gas, or any other form or state.

(27) Formation--A body of consolidated or unconsolidated rock characterized by a degree of lithologic homogeneity which is prevailingly, but not necessarily, tabular and is mappable on the earth's surface or traceable in the subsurface.

(28) Formation fluid--Fluid present in a formation under natural conditions as opposed to introduced fluids such as drilling mud.

(29) Fracture pressure--The pressure that, if applied to a subsurface formation, would cause that formation to physically fracture or result in initiation or propagation of fractures.

(30) Good faith claim--A factually supported claim based on a recognized legal theory to a continuing possessory right in an estate that includes the brine resources sought to be extracted through a brine production well.

(31) Injection well--A well into which fluids are being injected.

(32) Interested person--Any person who expresses an interest in an application, permit, or Class V spent brine return injection well.

(33) Limited English-speaking household--A household in which all members 14 years and older have at least some difficulty with English.

(34) Lithology--The description of rocks on the basis of their physical and chemical characteristics.

(35) Mechanical integrity--A Class V spent brine return injection well has mechanical integrity if:

(A) there is no significant leak in the casing, tubing, or packer (internal mechanical integrity); and

(B) there is no significant fluid movement into a USDW through channels adjacent to the injection well bore as a result of operation of the injection well (external mechanical integrity).

(36) Operator-- A person, acting for itself or as an agent for others and designated to the Commission as the one who has the primary responsibility for complying with its rules and regulations in any and all acts subject to the jurisdiction of the Commission.

(37) Owner--The owner of any facility or activity subject to regulation under the UIC program.

(38) Packer--A device lowered into a well to produce a fluid-tight seal.

(39) Person--A natural person, corporation, organization, government or governmental subdivision or agency, business trust, estate, trust, partnership, association, or any other legal entity.

(40) Plugging--The act or process of stopping the flow of water, oil, or gas into or out of a formation through a borehole or well penetrating that formation.

(41) Plugging record--A systematic listing of permanent or temporary abandonment of water, oil, gas, test, exploration and waste injection wells. The listing may contain a well log, description of amounts and types of plugging material used, the method employed for plugging, a description of formations which are sealed and a graphic log of the well showing formation location, formation thickness, and location of plugging structures.

(42) Pollution--The alteration of the physical, chemical, or biological quality of, or the contamination of, water that makes it harmful, detrimental, or injurious to humans, animal life, vegetation or property or to public health, safety, or welfare, or impairs the usefulness or the public enjoyment of the water for any lawful or reasonable purpose.

(43) Pressure--The total load or force per unit area acting on a surface.

(44) Schedule of compliance--A schedule of remedial measures included in a permit, including an enforceable sequence of interim requirements (for example, actions, operations, or milestone events) leading to compliance with the applicable statutes and regulations.

(45) Spent brine--Brine produced from a brine production well from which brine resources have been extracted. Spent brine may include non-hazardous process water and other additives used to facilitate brine resource extraction or reinjection.

(46) Surface casing--The first string of well casing to be installed in the well.

(47) Total dissolved solids--The total dissolved (filterable) solids as determined by use of the method specified in 40 CFR part 136.

(48) Transmissive fault or fracture--A fault or fracture that has sufficient permeability and vertical extent to allow fluids to move beyond the confining zone.

(49) Underground injection--Well injection.

(50) UIC--Underground injection control.

(51) UIC Program--The Underground Injection Control program under Part C of the Safe Drinking Water Act, including an "approved State program" as defined in 40 CFR §144.3.

(52) Underground source of drinking water (USDW)-- An aquifer or its portion which is not an exempted aquifer and which:

(A) supplies any public water system; or

(B) contains a sufficient quantity of ground water to supply a public water system and either:

(i) currently supplies drinking water for human consumption; or

(ii) contains fewer than 10,000 milligrams per liter total dissolved solids.

(53) Well--A bored, drilled, or driven shaft whose depth is greater than the largest surface dimension, or a dug hole whose depth is greater than the largest surface dimension.

(54) Well injection--The subsurface emplacement of fluids through a well.

(55) Well plug--A watertight and gastight seal installed in a borehole or well to prevent movement of fluids.

(56) Workover--An operation in which a down-hole component of a well is repaired or the engineering design of the well is changed. Workovers include operations such as sidetracking, the addition of perforations within the permitted injection interval, and the addition of liners or patches. For the purposes of this section, workovers do not include well stimulation operations.

(c) General requirements.

(1) A brine production project and all associated brine production wells and Class V spent brine return injection wells shall be permitted in accordance with the requirements of this section. No person may construct or operate such wells without a permit under this section.

(2) Applications and reports shall be signed in accordance with this paragraph.

(A) Applications. All applications shall be signed as follows:

(i) for a corporation, by a responsible corporate officer. A responsible corporate officer means a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy-making or decision-making functions for the corporation; or

(ii) for a partnership or sole proprietorship, by a general partner or the proprietor, respectively.

(B) Reports. All reports required by permits and other information requested by the Commission shall be signed by a person described in subparagraph (A) of this paragraph or by a duly authorized representative of that person. A person is a duly authorized representative only if:

(i) the authorization is made in writing by a person described in subparagraph (A) of this paragraph;

(ii) the authorization specifies an individual or position having responsibility for the overall operation of the regulated facility; and

(iii) the authorization is submitted to the Commission before or together with any report of information signed by the authorized representative.

(C) Certification. Any person signing a document under subparagraph (A) or (B) of this paragraph shall make the following certification: "I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gathered and evaluated the information submitted. Based on my inquiry of the person or persons who manage the system, or who are directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information."

(3) Operators of all Class V spent brine return injection wells shall re-inject spent brine into the brine field from which the brine was produced.

(4) All brine production wells and Class V spent brine return injection wells shall be drilled and completed or recompleted, operated, maintained, and plugged in accordance with the requirements of this section and the brine production project permit.

(5) The Commission shall assign each brine production project a Commission lease number. All brine project operators shall ascertain from the appropriate schedule the lease number assigned to each separate brine production project, and thereafter include on each Commission-required form or report the exact brine production project name and its assigned number as they appear on the current schedule for all leases.

(6) An applicant for or permittee of a brine production project and associated wells shall comply with the requirements of this chapter, including but not limited to:

(A) §3.1 of this title (relating to Organization Report; Retention of Records; Notice Requirements);

(B) §3.5 of this title (relating to Application To Drill, Deepen, Reenter, or Plug Back);

(C) §3.11 of this title (relating to Inclination and Directional Surveys Required);

(D) §3.12 of this title (relating to Directional Survey Company Report);

(E) §3.16 of this title (relating to Log and Completion or Plugging Reports)

(F) §3.17 of this title (relating to Pressure on Bradenhead)

(G) §3.18 of this title (relating to Mud Circulation Required);

(H) §3.19 of this title (relating to Density of Mud-Fluid);

(I) §3.36 of this title (relating to Oil, Gas, Brine, or Geothermal Resource Operation in Hydrogen Sulfide Areas); and

(J) §3.80 of this title (relating to Commission Oil and Gas Forms, Applications, and Filing Requirements).

(7) In addition to the requirements of §3.13 of this title (relating to Casing, Cementing, Drilling, Well Control, and Completion Requirements), all wells associated with a brine production project shall use casing and cement designed to withstand the anticipated pressurization and formation fluids that are capable of negatively impacting the integrity of casing and/or cement such that it presents a threat to USDWs or oil, gas, or geothermal resources.

(8) All operators of wells drilled and operated in association with a brine production project shall comply with the requirements of §3.14 of this title (relating to Plugging), §3.15 (relating to Surface Equipment Removal Requirements and Inactive Wells), and §3.35 (relating to Procedures for Identification and Control of Wellbores in Which Certain Logging Tools Have Been Abandoned), except that the operator shall plug all wells associated with a brine production project and remove all wastes, storage vessels, and equipment from the site within one year of cessation of brine production project operations.

(9) All operators of wells drilled and operated in association with a brine production project shall comply with the requirements of §3.78 of this title (relating to Fees and Financial Security Requirements), as the requirements are applicable to brine production projects, except that, prior to spudding, the operator shall provide financial security in an amount estimated to plug each well in the brine production project after cessation of brine production project operations. Notwithstanding the provisions of §3.78(i) of this title, for an operator of a brine production project who has satisfied its financial security requirements by filing a cash deposit, the Commission shall refund to the operator the amount estimated to plug each well following its plugging if the amount of the deposit remaining after the refund would be sufficient to plug all remaining wells in the brine production project.

(10) No person may knowingly make any false statement, representation, or certification in any application, report, record, or other document submitted or required to be maintained under this section or under any permit issued pursuant to this section, or falsify, tamper with, or knowingly render inaccurate any monitoring device or method required to be maintained under this section or under any permit issued pursuant to this section.

(d) Spacing, acreage, density and field rules; exceptions.

(1) Spacing. All brine production wells and Class V spent brine return injection wells shall be completed within the brine production project area and no less than one-half mile from the boundary of the brine production project area and no less than one-half mile from any interest within the brine production project area that is not participating in the project, unless special field rules provide different spacing requirements or the applicant obtains an exception to this paragraph pursuant to paragraph (4) of this subsection.

(2) Acreage and density.

(A) An applicant for a brine production project permit shall designate and assign to the project acreage within the applicable brine field and indicate the total number of acres in the permit application required by subsection (e)(3) of this section. The minimum acreage is 1,280 acres per brine production well included in the brine production project unless special field rules provide different well density requirements or the applicant obtains an exception to this paragraph pursuant to paragraph (4) of this subsection.

(B) Upon completion of a brine production well in a brine production project area and filing the completion report with the Commission, the applicant may elect to file a plat assigning acreage in the brine production project area to the brine production well; however, the applicant is not required to assign acreage to an individual brine production well, provided the total number of acres assigned to the brine production project area divided by the total number of brine production wells equals or exceeds 1,280 acres, unless special field rules provide different well density requirements or the applicant obtains an exception to the density requirements pursuant to paragraph (4) of this subsection.

(C) An applicant shall not assign more than 5,120 acres in a brine field to a brine production well unless special field rules provide for different limits.

(D) If the operator elects to file a plat assigning acreage to a brine production well, the two farthermost points of acreage assigned to the well shall not exceed 23,760 feet unless special field rules provide for a different limit, and the acreage assigned shall include all productive portions of the wellbore.

(E) Multiple assignment of the same acreage in a brine field to more than one brine production well is not permitted. However, this limitation shall not prevent the reformation of brine production projects so long as:

(i) no multiple assignment of acreage occurs; and

(ii) such reformation does not violate other regulations.

(F) The acreage included in a brine production project area shall consist of acreage for which the operator has a good faith claim to produce brine resources.

(i) Non-contiguous acreage included in the same brine production project area may not be separated by greater than the minimum spacing distance for wells provided by paragraph (1) of this subsection, as altered by any applicable special field rules.

(ii) An operator may obtain an exception to the contiguity requirements of clause (i) of this subparagraph pursuant to paragraph (4)(C) of this subsection.

(G) The acreage limits provided by this paragraph are the minimum and maximum amounts of acreage in a brine field that may be assigned to an individual well at the operator's election and shall not be construed as a limit on the sizes of either a brine production project area or a pooled unit for production of brine resources.

(3) Brine field designation and field rules.

(A) Application for new brine field designation. A new brine field designation may be made by the Commission after a hearing after notice to all operators of brine production wells within five miles of the brine discovery well. The applicant shall provide proper evidence proving that a well is completed in a new field.

(i) The applicant shall submit a legible area map, drawn to scale, which shows the following:

(I) all oil, gas, brine production, and abandoned wells within at least a five-mile radius of the brine well claimed to be a discovery well;

(II) the producing intervals of all wells identified in subclause (I) of this clause;

(III) all Commission-recognized fields within a two and one-half mile radius of the brine well claimed to be a discovery well identified by Commission-assigned field names, names of the producing formations, and approximate average depth of the producing interval;

(IV) the total depth of all wells identified in subclause (I) of this clause that penetrated the top of the proposed new field; and

(V) scale, legend, and name of person who prepared the map.

(ii) The applicant shall submit a list of the names and addresses of all operators of wells within five miles of the brine discovery well.

(iii) The applicant shall submit a complete electric log of the brine well. Any electric log filed shall be considered public information pursuant to §3.16 of this title.

(iv) The applicant shall submit a bottom-hole pressure for brine production wells submitted on the appropriate form. This bottom-hole pressure may be determined by a pressure build-up test, drill stem test, or wire-line formation tester. Calculations based on fluid level surveys or calculations made on flowing wells using shut-in wellhead pressures may be used if no test data is available.

(v) The applicant shall submit a subsurface structure map and/or cross sections, if separation is based on structural differences, including faulting and pinch-outs. The structure map shall show the contour of the top of the brine field and the lines of cross section. The cross sections shall be prepared from comparable electric logs (not tracings) with the wells, producing formation, and brine field identified. The engineer or geologist who prepared the map and cross section shall sign and seal them.

(vi) The applicant shall submit reservoir pressure measurements or calculations, if separation is based on pressure differentials.

(vii) The applicant shall submit core data, drillstem test data, cross sections of nearby wells, and/or production data estimating the fluid level, if separation is based on differences in fluid levels. The applicant shall obtain the fluid level data within 10 days of the potential test date.

(viii) The applicant shall submit evidence that demonstrates that the new brine field is effectively separated from any other brine field or oil or gas field previously shown to be commercially productive.

(B) Temporary brine field rules.

(i) The Commission will accept applications for temporary brine field rule hearings for brine fields after the first well has been completed in a brine field.

(ii) When requesting such hearings, the applicant shall furnish the Commission with a list of the names and addresses of all operators of wells within five miles of the brine discovery well.

(iii) At the hearing on the adoption of temporary brine field rules, the applicant bears the burden of establishing that each of the proposed temporary brine field rules is reasonably expected to protect freshwater resources, protect correlative rights, prevent waste of recoverable brine resources, and promote the production of additional brine resources in an orderly and efficient manner.

(iv) Temporary brine field rules shall remain effective until:

(I) 18 months after adoption; or

(II) permanent brine field rules are adopted.

(C) Permanent brine field rules.

(i) After temporary brine field rules have been effective in a brine field for at least 12 months, the operator of a brine production well in the brine field subject to temporary brine field rules or the Commission may request a hearing to adopt permanent brine field rules for the brine field in which the operator's well is located.

(ii) An operator requesting a hearing to adopt permanent brine field rules shall furnish the Commission a list of all operators within five miles of the brine discovery well.

(iii) If permanent field rules are not adopted, temporary field rules adopted under subparagraph (B) of this paragraph expire after 18 months and the statewide field requirements of this section apply to operations within the applicable brine field.

(4) Exceptions to spacing, density, and contiguity requirements.

(A) An exception to paragraph (1) of this subsection or paragraph (2)(A) - (C) of this subsection may be granted after a public hearing held after notice to all persons described in subparagraph (B) of this paragraph. An exception to paragraph (2)(F) of this subsection may be granted after a public hearing held after notice to all persons described in subparagraph (C) of this paragraph. At a hearing on an exception, the burden shall be on the applicant to establish that an exception to this section is necessary either to prevent waste or to protect correlative rights.

(B) In addition to the notice required under subsection (f) of this section, an applicant seeking an exception to the spacing or density requirements shall file with its application the names and mailing addresses of the following persons for tracts within the minimum spacing distance for the proposed well and the brine field:

(i) the designated operator;

(ii) all lessees of record for tracts with no designated operator; and

(iii) all owners of record of unleased mineral interests.

(C) In addition to the notice required under subsection (f) of this section, an applicant seeking an exception to the contiguity requirements of paragraph (2)(F) of this subsection shall file with its application the names and mailing addresses of the following persons for tracts located between the non-contiguous portions of its proposed project area that are farther apart than the minimum spacing distance for wells in the brine field:

(i) the designated operator;

(ii) all lessees of record for tracts with no designated operator; and

(iii) all owners of record of unleased mineral interests.

(D) If, after diligent efforts, the applicant is unable to ascertain the name and address of one or more persons required by this paragraph to be notified, then the applicant shall notify such persons by publishing notice of the application in a form approved by the Commission. The applicant shall publish the notice once each week for two consecutive weeks in a newspaper of general circulation in the county or counties in which the brine production project well will be located. The first publication shall be published at least 14 days before the protest deadline in the notice of application.

(e) Brine production project permit application.

(1) Any person who proposes to operate a brine production project shall submit to the Director an application for a brine production project permit. The application shall be made under this section or under special field rules governing the particular brine field, or as an exception thereto, and filed with the Commission on a form approved by the Commission.

(2) An application for a brine production project permit shall be accompanied by an application for at least one injection well and shall include the information required by paragraph (3) of this subsection, as applicable. The applicant is not required to submit permit applications for the other individual brine production and Class V spent brine return injection wells at the time the applicant submits its application for a brine production project permit. Unless otherwise specified in the brine production project permit, once the brine production project permit has been issued, the operator may operate additional brine production wells and Class V spent brine return injection wells as part of the brine production project. The operator shall obtain permits for those wells prior to commencing operations. Requirements for obtaining a Class V spent brine return injection well permit are specified in paragraph (4) of this subsection. Notice in addition to the notice required for the brine production project by subsection (f) of this section is not required for the individual wells unless the operator requests an exception to the spacing, density, or acreage requirements or additional notice is required by the permit.

(3) An application for a brine production project permit shall comply with the requirements of this paragraph.

(A) The application shall include the name, mailing address, and physical location of the brine production project for which the application is submitted.

(B) The application shall include the applicant's name, mailing address, telephone number, P-5 Organization Report number, and a statement indicating whether the applicant operator is the owner of the facility.

(C) The application shall specify the proposed use or uses for the brine produced by the project.

(D) The application shall specify the estimated maximum number of brine production wells and Class V spent brine return injection wells that will be operated within the brine production project.

(E) The application shall designate the total number of acres included in the proposed brine production project area, which shall equal not less than 1,280 acres per brine production well unless special field rules provide otherwise.

(F) The application shall specify the brine field from which the brine will be produced and spent brine reinjected, including the top and bottom depths of the field throughout the area of review.

(G) The application shall include complete electric logs of representative brine production wells and Class V spent brine return injection wells or complete electric logs of representative nearby wells. On the logs, the applicant shall identify and indicate the depths of the geologic formations between the land surface and the top of the brine field.

(H) The application shall include wellbore diagrams showing the completions that will be used for brine production wells and Class V spent brine return injection wells, including casing and liner sizes and depths and a statement indicating that such wells will be drilled, cased, cemented, and completed in accordance with the requirements of §3.13 of this title as those requirements may be revised by this section. The statement shall also include information to demonstrate that the casing and cement used in the completion of each brine production well and each Class V spent brine return injection well is designed to withstand the anticipated pressurization and formation fluids that are capable of negatively impacting the integrity of casing and/or cement such that it presents a threat to USDWs or oil, gas, or geothermal resources. The wellbore diagrams shall show the proposed arrangement of the downhole well equipment and specifications of the downhole well equipment. A single wellbore diagram may be submitted for multiple wells that have the same configuration, provided that each well with that type of configuration is identified on the wellbore diagram and the diagram identifies the deepest cement top for each string of casing among all the wells covered by that diagram.

(I) The application shall include information to characterize the brine field from which the brine will be produced and into which the spent brine will be reinjected, including the following:

(i) an isopach map showing thickness and areal extent of the brine field;

(ii) lithology, grain mineralogy, and matrix cementing of the brine field;

(iii) effective porosity of the brine field and the method used to determine effective porosity;

(iv) vertical and horizontal permeability of the brine field and the method used to determine permeability;

(v) the occurrence and extent of natural fractures and solution features within the brine production project;

(vi) chemical and physical characteristics of the fluids contained in the brine field that may potentially impact casing or cement;

(vii) the bottom hole temperature and pressure of the brine field;

(viii) formation fracture pressure of the brine field, the method used to determine fracture pressure and the expected direction of fracture propagation. Calculations demonstrating injection of spent brine into the proposed brine field shall not exceed the fracture pressure gradient and information showing injection into the brine field will not initiate fractures through the confining zone;

(ix) a description of the proposed well stimulation program, if applicable, including a description of the stimulation fluids, and a determination that the well stimulation will not compromise containment of the brine field;

(x) the vertical distance separating the top of the brine field from the base of the lowest USDW;

(xi) a demonstration, such as geologic maps and cross-sections, that the brine field into which the spent brine will be injected is the same formation from which the brine will be produced; and

(xii) any other information necessary to characterize the brine field.

(J) The application shall include information to characterize the proposed confining zone, including the following:

(i) the geological name and the top and bottom depths of the formation making up the confining zone;

(ii) an isopach map showing thickness and areal extent of the confining zone;

(iii) lithology, grain mineralogy, and matrix cementing of the confining zone;

(iv) the vertical distance separating the top of the confining zone from the base of the lowest USDW; and

(v) any other information necessary to characterize the confining zone.

(K) The application shall include the proposed operating data, including the following:

(i) the maximum daily brine production rate;

(ii) the maximum daily injection rate and maximum injection pressure; and

(iii) the proposed test procedure to be used to determine mechanical integrity of the Class V spent brine return injection wells.

(L) The application shall include a letter from the Geologic Advisory Unit of the Commission's Oil and Gas Division stating that the use of the brine field for the injection of spent brine will not endanger usable quality water or USDWs.

(M) The application shall include an accurate plat with surveys of a scale sufficient to legibly show the entire extent of the area of review. The plat shall include the following:

(i) the area of review outlined on the plat using either a heavy line or crosshatching;

(ii) the location, to the extent anticipated at the time of the application, of each well within the brine production project area that the applicant intends to use for the brine production project including each existing well that may be converted to brine production or Class V spent brine return injection, each well the applicant intends to drill for brine production, each well the applicant intends to drill for project monitoring, and each Class V spent brine return injection well. If the wells are horizontal or deviated wells, the plat shall include the surface location of the proposed drilling site, penetration point, perforated casing or open hole through which brine will be produced or reinjected, terminus location, and a line showing the distance in feet from the perimeter of the area of review to the nearest point of extraction or injection on the lateral leg of the horizontal well;

(iii) the type, location, and depth of all wells of public record within the area of review that penetrate the top of the brine field. The applicant shall include the following information with the map:

(I) a tabulation of the wells showing the dates the wells were drilled and the current status of the wells;

(II) completion records for all wells and plugging records for plugged and abandoned wells; and

(III) a corrective action plan for any known wells in the area of review that penetrate the brine field and that may allow fluid migration into USDWs from the brine field for which the applicant cannot demonstrate proper completion, plugging, or abandonment. The Director may approve a phased corrective action plan;

(iv) the geographic location information of the wells, including the Latitude/Longitude decimal degree coordinates in the WGS 84 coordinate system, a labeled scale bar, and indication of the northerly direction; and

(v) a certification by a person knowledgeable of the facts pertinent to the application that the plat is accurately drawn to scale and correctly reflects all pertinent and required data.

(N) The application shall include a plat showing:

(i) the outline of the brine production project area;

(ii) the operators of tracts in the brine production project area and tracts within the area of review;

(iii) owners of all leases of record for tracts that have no designated operator in the brine production project area and tracts within the area of review;

(iv) owners of record of unleased mineral interests within the brine field for tracts in the brine production project area and tracts within the area of review;

(v) surface owners of tracts in the brine production project area and within the area of review; and

(vi) the names and addresses of all persons listed in clause (ii) through (v) of this subparagraph. If the names and addresses of the persons in clause (ii) through (v) of this subparagraph cannot be included on the plat, the applicant shall include the names and addresses on a separate sheet attached to the plat. The applicant shall determine the names and addresses of the surface owners from the current county tax rolls or other reliable sources and shall identify the source of the list. If the Director determines that, after diligent efforts, the applicant has been unable to ascertain the name and address of one or more surface owners, the Director may waive the requirements of this subparagraph with respect to those surface owners.

(O) The application shall include a subsurface structure map and/or cross sections, including faulting and pinch-outs. The structure map shall show the contour of the top of the brine field and the lines of cross section. The cross sections shall be prepared from comparable electric logs (not tracings) and shall identify the wells, brine field, and any hydrocarbon reservoir.

(P) The application shall include a printed copy or screenshot showing the results of a survey of information from the United States Geological Survey (USGS) regarding the locations of any historical seismic events within a circular area of 100 square miles (a circle with a radius of 9.08 kilometers) centered around the proposed injection well location.

(Q) The application shall include a certification that the applicant has a good faith claim to produce the brine resources for the tracts included in the brine production project area.

(R) The application shall include a proposed plugging and abandonment plan.

(S) The applicant shall ensure that, if required under Texas Occupations Code, Chapter 1001, relating to Texas Engineering Practice Act, or Chapter 1002, relating to Texas Geoscientists Practice Act, respectively, the geologic and hydrologic evaluations required under this section are conducted by a licensed professional engineer or geoscientist who shall affix the appropriate seal on the resulting report of such evaluations.

(T) The application shall include any other information the Director may reasonably require to enable the Commission to determine whether to issue a permit for the brine production project, including the associated brine production wells and Class V spent brine return injection wells.

(4) Prior to commencement of injection operations into any Class V spent brine return injection well within the brine production project area, the operator shall file an application for an individual well permit with the Commission in Austin. The individual well permit application shall include the following:

(A) the well identification and, for a new well, a location plat;

(B) the location of any well drilled within one-quarter mile of the injection well after the date of application for the brine production project permit and the status of any well located within one-quarter mile of the injection well that has been abandoned since the date the brine production project permit was issued, including the plugging date if such well has been plugged;

(C) a description of the well configuration, including casing and liner sizes and setting depths, the type and amount of cement used to cement each casing string, depth of cement tops, and tubing and packer setting depths;

(D) a description of any additives used in the brine production project and reinjected with the spent brine into the Class V spent brine return well;

(E) an application fee in the amount of $100 per well; and

(F) any other information required by the brine production project permit.

(5) Criteria for exempted aquifers. An aquifer or a portion thereof which meets the criteria for an "underground source of drinking water" may be determined under 40 CFR §144.7 to be an "exempted aquifer" if it meets the criteria in paragraphs (a) through (c) of 40 CFR §146.4. The Commission adopts 40 CFR §144.7 and §146.4 by reference, effective January 6, 2025.

(6) All individual Class V spent brine return injection wells covered by a brine production project permit shall be completed, operated, maintained, and plugged in accordance with the requirements of subsection (j) of this section and the brine production project permit.

(f) Notice and hearing.

(1) Notice to certain communities. The applicant shall identify whether any portion of the AOR encompasses an Environmental Justice (EJ) or Limited English-Speaking Household community using the most recent U.S. Census Bureau American Community Survey data. If the AOR incudes an EJ or Limited English-Speaking Household community, the applicant shall conduct enhanced public outreach activities to these communities, including a public meeting. Efforts to include EJ and Limited English-Speaking Household communities in public involvement activities in such cases shall include:

(A) published meeting notice in English and the identified language (e.g., Spanish);

(B) comment forms posted on the applicant's webpage and available at the public meeting in English and the identified language;

(C) interpretation services accommodated upon request;

(D) English translation of any comments made during any comment period in the identified language; and

(E) to the extent possible, public meeting venues near public transportation.

(2) Notice. The applicant for a brine production project permit shall give notice of the application as follows.

(A) Persons to notify. The applicant for a brine production project permit shall notify:

(i) operators on tracts within the area of review;

(ii) owners of all leases of record for tracts that have no designated operator within the area of review;

(iii) owners of record of unleased mineral interests within the area of review and within the brine field;

(iv) all surface owners identified on the plat described in subsection (e)(3)(N)(ii) of this section;

(v) the city clerk or other appropriate city official of a city for which any portion falls within the area of review;

(vi) the county clerk of any county or counties for which any portion falls within the area of review; and

(vii) any other person designated by the Director.

(B) Method of notice.

(i) The applicant for a brine production project permit shall mail or deliver to persons listed in subparagraph (A) of this paragraph notice of the brine production project permit application in a form approved by the Commission. The applicant shall provide notice after staff determines than an application is complete pursuant to subsection (g)(1) of this section.

(ii) The applicant shall publish notice of the brine production project permit application in a form approved by the Commission. The applicant shall publish the notice once each week for two consecutive weeks in a newspaper of general circulation of any county or counties for which any portion falls within the area of review. The first notice shall be published at least 14 days before the protest deadline in the notice of application. The applicant shall file with the Commission a publisher's affidavit or other evidence of publication.

(C) Contents of notice. The notice shall be made using the form prescribed by the Commission, which shall include the following information:

(i) the county or counties within which the brine production project area of review is located;

(ii) a copy of the plat required by subsection (e)(3)(M) of this section;

(iii) the name of the brine field;

(iv) the depth to the top of the brine field;

(v) the proposed life of the brine production project; and

(vi) a statement that an affected person may file a protest within 30 days of the date of the notice and any interested person may submit comments to the Commission within 30 days of the date of the notice.

(D) Notice of Class V spent brine return injection wells. Once an applicant complies with the notice required to obtain a brine production project permit and the permit has been issued, no notice shall be required when filing an application for an individual injection well permit for any Class V spent brine return injection well covered by the brine production permit unless otherwise provided in the permit.

(E) Notice of brine production well. Once an applicant complies with the notice required to obtain a brine production permit and the permit has been issued, no notice shall be required when filing an application for an individual brine production well permit for any brine production well covered by the brine production permit unless otherwise provided in the permit or unless an exception is requested.

(3) Comments, protests, and requests for hearing. Notice of an application will allow at least 30 days for public comment. Beginning on the date of the notice, any affected person has 30 days to protest the application, and any interested person has 30 days to submit written comments.

(4) Hearings.

(A) The Commission shall hold a hearing when:

(i) the Commission receives a written protest from an affected person within 30 days after notice of the application is given in accordance with this subsection;

(ii) the Director denies the application and the operator requests a hearing within 30 days of the notice of administrative denial;

(iii) the Director issues the permit and the operator requests a hearing to contest certain permit conditions; or

(iv) the Director determines that a hearing is in the public interest.

(B) Notice of a hearing will be given at least 30 days before the hearing. The public comment period under paragraph (3) of this subsection will automatically be extended to the close of any hearing under this paragraph.

(C) At any hearing, the burden shall be on the applicant.

(D) After hearing, the administrative law judge and technical examiner shall recommend final Commission action.

(g) Commission action on permit applications.

(1) Permitting procedures.

(A) Initial permit application review. Upon receipt of an application for a permit, the Director will review the application for completeness. Within 30 days after receipt of the application, the Director will notify the applicant in writing whether the application is complete or deficient. A notice of deficiency will state the additional information necessary to complete the application, and a date for submitting this information. The application will be deemed withdrawn if the necessary information is not received by the specified date, unless the Director has extended this date upon request of the applicant. Upon timely receipt of the necessary information, the Director will notify the applicant that the application is complete. The Director will not begin processing a permit until the application is complete.

(B) Administrative action on application. When no timely protest is received from an affected person, the Director may administratively grant an application for a brine production project permit, including the associated wells, if the applicant provides sufficient evidence to demonstrate that the brine production project will not endanger USDWs or human health or the environment.

(2) Application for an amended permit. The permittee shall file an application to amend a brine production project permit if the permittee wishes to make substantial changes such as change the exterior boundaries of, or maximum number of wells authorized in, the brine production project area or alter permit conditions.

(3) Permit application denial. If the Director administratively denies a permit application, a notice of administrative denial will be mailed to the applicant. The applicant will have a right to a hearing on request. At any such hearing, the burden shall be on the applicant. After hearing, the administrative law judge and technical examiner shall recommend final Commission action.

(h) Modification, revocation and reissuance, and termination of permits. A permit may be modified, revoked and reissued, or terminated by the Commission either upon the written request of the operator or upon the Commission's initiative, but only for the reasons and under the conditions specified in this subsection. Except for minor modifications made under paragraph (2) of this subsection, the Commission will follow the applicable procedures in paragraph (1) of this subsection. In the case of a modification, the Commission may request additional information or an updated application. In the case of a revocation and reissuance, the Commission will require a new application. If a permit is modified, only the conditions subject to modification are reopened. The term of a permit may not be extended by modification. If a permit is revoked and reissued, the entire permit is reopened and subject to revision, and the permit is reissued for a new term.

(1) Modification, or revocation and reissuance. The following are causes for modification, or revocation and reissuance:

(A) when material and substantial alterations or additions to the facility occur after permit issuance and justify permit conditions that are different or absent in the existing permit;

(B) the Commission receives new information;

(C) the standards or regulations on which the permit was based have been changed by promulgation of amended standards or regulations or by judicial decision after the permit was issued;

(D) the Commission determines good cause exists for modifying a compliance schedule, such as an act of God, strike, flood, materials shortage, or other event over which the operator has little or no control and for which there is no reasonably available remedy;

(E) cause exists for terminating a permit under paragraph (3) of this subsection, and the Commission determines that modification, or revocation and reissuance, is appropriate; or

(F) a transfer of the permit is proposed.

(2) Minor modifications. With the permittee's consent, the Director may make minor modifications to a permit administratively, without following the procedures of paragraph (1) of this subsection. Minor modifications may only:

(A) correct clerical or typographical errors, or clarify any description or provision in the permit, provided that the description or provision is not changed substantively;

(B) require more frequent monitoring or reporting;

(C) change construction requirements provided that any changes shall comply with the requirements of subsection (j)(4) of this section; or

(D) allow a transfer of the permit where the Director determines that no change in the permit is necessary other than a change in the name of the permittee, provided that a written agreement between the current permittee and the new permittee containing a specific data for the transfer of permit responsibility, coverage, and liability has been submitted to the Commission.

(3) Termination. The following are causes for terminating a permit during its term, or for denying a permit renewal application:

(A) the permittee fails to comply with any condition of the permit or this section;

(B) the permittee fails to disclose fully all relevant facts in the permit application or during the permit issuance process, or misrepresents any relevant fact at any time;

(C) a material change of conditions occurs in the operation or completion of the well, or there are material changes in the information originally furnished; or

(D) the Commission determines that the permitted injection endangers human health or the environment, or that pollution of USDWs is occurring or is likely to occur as a result of the permitted injection.

(4) Duty to provide information. The permittee shall also furnish to the Commission, within a time specified by the Commission, any information that the Commission may request to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit, or to determine compliance with the permit. The permittee shall also furnish to the Commission, upon request, copies of records required to be kept under the conditions of the permit.

(i) Permit conditions.

(1) Access by Commission. The permittee shall allow any member or employee of the Commission, on proper identification, to:

(A) enter upon the premises where a regulated activity is conducted or where records are kept under the conditions of the permit;

(B) have access to and copy, during reasonable working hours, any records required to be kept under the conditions of the permit;

(C) inspect any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under the permit; and

(D) sample or monitor any substance or parameter for the purpose of assuring compliance with the permit or as otherwise authorized by the Texas Water Code, §27.071, or the Texas Natural Resources Code, §91.1012.

(2) Commission testing. The Commission may make any tests on any well at any time necessary for regulation of wells under this section, and the operator of such wells shall comply with any directives of the Commission to make such tests in a proper manner.

(3) Duty to comply. The permittee shall comply with all conditions of the permit. Any permit noncompliance is grounds for enforcement action, for permit termination, revocation and reissuance, or modification, or for denial of a permit renewal application.

(4) Need to halt or reduce activity not a defense. It is not a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of the permit.

(5) Duty to mitigate. The permittee shall take all reasonable steps to minimize and correct any adverse effect on the environment resulting from noncompliance with the permit.

(6) Proper operation and maintenance. The permittee shall at all times properly operate and maintain all facilities and systems of treatment and control, and related appurtenances, that are installed or used by the permittee to achieve compliance with the conditions of the permit. Proper operation and maintenance includes effective performance, adequate funding, adequate permittee staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up and auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of the permit.

(7) Property rights. The permit does not convey any property rights of any sort, or any exclusive privilege. However, a valid permit is a property interest that may not be modified, suspended, or revoked without due process of law.

(8) Financial assurance. The permit shall require the permittee to maintain financial responsibility and resources to plug and abandon all brine mining production wells and Class V spent brine return injection wells and to remove all wastes, storage vessels, and equipment from the site within one year of cessation of brine production operations. The permittee shall show evidence of such financial responsibility to the Director in accordance with the requirements of §3.78 of this title by submitting a cash deposit, performance bond, or letter of credit in a form prescribed by the Commission. Such bond or letter of credit shall be maintained until the well is plugged in accordance with paragraph (16) of this subsection.

(9) Duration. A permit issued under this section is effective for the duration of the brine production project. The Commission will review each permit issued pursuant to this section at least once every five years to determine whether just cause exists for modification, revocation and reissuance, or termination of the permit. The Commission may modify, revoke and reissue, or terminate a permit for just cause only after notice and opportunity for a hearing.

(10) Transfers. A brine production project permit is not transferable to any person except by modification, or revocation and reissuance of the permit to change the name of the permittee and incorporate other necessary requirements associated with the permittee name change.

(11) Permit renewal. Any person who has obtained a permit under this section and who wishes to continue to operate the brine production project and brine production wells after the permit expires shall file an application for a new permit at least 180 days before the existing permit expires, unless a later date has been authorized by the Director.

(12) Permit actions. The permit may be modified, revoked and reissued, or terminated for cause. The filing of a request by the permittee for a permit modification, revocation and reissuance, or termination, or a notification of planned changes or anticipated noncompliance does not stay any permit condition.

(13) Compliance with permit. All brine production wells and Class V spent brine return injection wells shall be drilled, converted, completed, operated, or maintained in accordance with the brine production project permit.

(14) Monitoring and records.

(A) Samples and measurements taken for the purpose of monitoring shall be representative of the monitored activity.

(B) The permittee shall retain records of all monitoring information, including all calibration and maintenance records and all original chart recordings for continuous monitoring instrumentation, copies of all reports required by the permit, and records of all data used to complete the permit application, for at least three years from the date of the sample, measurement, report, or application. This period may be extended by the Commission at any time.

(C) Records of monitoring information shall include the date, exact place, and time of the sampling or measurements; the individuals who performed the sampling or measurements; the dates analyses were performed; the individuals who performed the analyses; the analytical techniques or methods used; and the results of the analyses.

(15) Reporting and record retention.

(A) The permittee shall submit to the Director, within the time specified by the Director, any information that the Director may reasonably request to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit, or to determine compliance with the permit. The permittee shall also furnish to the Director, upon request, copies of records required to be kept under the conditions of the permit.

(B) The permittee shall retain records of all information required by the permit for at least five years from the date of commencement of brine production. This period may be extended by request of the Commission at any time.

(C) The permittee shall file a report of the volumes of brine, oil, and gas produced by each brine production well during the preceding month. The report shall be filed with the Commission by the 15th calendar day of the month following the period covered by the report.

(D) The permittee shall notify the Director at such times as the permit requires before conversion or abandonment of a well associated with a brine production project.

(E) The permittee shall report to the Commission any noncompliance, including any spills or leaks from brine receptacles or pipelines, that may cause waste or confiscation of property or endanger surface or subsurface water, human health or the environment.

(i) An oral report shall be made to the appropriate district office immediately after the permittee becomes aware of the noncompliance.

(ii) A written report shall be filed with the Director and the appropriate district office within five days of the time the permittee becomes aware of the noncompliance. The written report shall contain the following information:

(I) a description of the noncompliance and its cause;

(II) the period of noncompliance, including exact dates and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue; and

(III) steps planned or taken to reduce, eliminate, and prevent recurrence of the noncompliance.

(F) If the permittee becomes aware that it failed to submit any relevant facts or submitted incorrect information in a permit application or a report to the Commission, the permittee shall promptly submit the relevant facts or correct information.

(16) Plugging. The operator of a brine production project shall plug all wells associated with the brine production project in accordance with the provisions of §3.14 of this title, except that the well shall be plugged within one year after cessation of the brine production project. For good cause, the Director may grant a reasonable extension of time in which to plug the wells if the operator submits a proposal that describes actions or procedures to ensure that the wells will not endanger USDWs during the period of the extension.

(17) Identification. Each property that produces brine resources and each well associated with a brine production project and tank shall at all times be clearly identified as follows.

(A) A sign shall be posted at the principal entrance to each such property which shall show the name by which the property is commonly known and is carried on the records of the Commission, the name of the permittee, and the number of acres in the property.

(B) A sign shall be posted at each well site which shall show the name of the property, the name of the permittee, and the well number.

(C) A sign shall be posted at or painted on each tank that is located on or serving each property, which signs shall show, in addition to the information provided for in subparagraph (A) of this paragraph, the Commission lease number for the formation from which brine in the tank is produced.

(D) The signs and identification required by this section shall be in the English language, clearly legible, and in the case of the signs required by subparagraphs (A), (B), and (C) of this paragraph shall be in letters and numbers at least one inch in height.

(18) Dikes or fire walls. Dikes or fire walls shall be erected and maintained around all permanent tanks, or battery of tanks, that are:

(A) within the corporate limits of any city, town, or village;

(B) closer than 500 feet to any highway or inhabited dwelling;

(C) closer than 1,000 feet to any school or church; or

(D) so located as to be deemed by the Commission to be an objectionable hazard.

(19) Additional conditions. The Commission reserves the right to include additional permit conditions if it determines the conditions are necessary to ensure compliance with the requirements in this section and to prevent waste, prevent the confiscation of property, or prevent pollution.

(j) Additional permit conditions for Class V spent brine return injection wells. In addition to the conditions in subsection (i) of this section, Class V spent brine return injection wells shall be subject to the following.

(1) Unauthorized injection prohibited. No person may operate a Class V spent brine return injection well without obtaining a permit from the Commission under this section. No person may begin constructing a new Class V spent brine return injection well until the Commission has issued a permit to drill, deepen, plug back, or reenter the well under §3.5 of this title and a permit to operate the injection well under this section.

(2) Injected fluid restricted to brine field. No person may operate a Class V spent brine return injection well in a manner that allows fluids to escape into USDWs from the brine field from which it was produced. If fluids from a Class V spent brine return injection well are migrating out of the brine field into USDWs, the permittee shall immediately cease injection operations in the well or wells most proximate to the location where fluids have been detected in USDWs and perform the necessary corrective action or plug the injection well.

(3) Permit standards. No person may operate a Class V spent brine return injection well in a manner that allows fluid to escape from the permitted brine field or the movement of fluids containing any contaminant into USDWs, if the presence of that contaminant may cause a violation of any primary drinking water regulation or may otherwise adversely affect the health of persons. If injected fluids migrate into USDWs, or cause formation fluid to migrate into USDWs, the permittee shall immediately cease injection operations. All permits for Class V spent brine return injection wells issued under this section shall include the conditions required by this section and any other conditions reasonably necessary to prevent the pollution of USDWs.

(4) Construction requirements for Class V spent brine return injection wells. All Class V spent brine mining injection wells shall be drilled and completed or recompleted, operated, maintained, and plugged in accordance with the requirements of this section and the Class V spent brine return injection well permit.

(A) Permits shall specify drilling and construction requirements to assure that the injection operations shall not endanger USDWs. No changes to the construction of a well may be physically incorporated into the construction of the well prior to approval of the modifications by the Director.

(B) In addition to the casing and cementing requirements of §3.13 of this title, the operator shall:

(i) for all newly drilled Class V spent brine return injection wells, drill a sufficient depth into the brine field to ensure that when the well is logged prior to setting the long string the operator will be able to identify the top of the brine field and verify that the fluid will be injected only into the brine field;

(ii) set and cement surface casing from at least 100 feet below the lowermost base of usable quality water as defined by the Geologic Advisory Unit to the surface, regardless of the total depth of the well;

(iii) set and cement long string casing at a minimum from the top of the brine field to the surface unless the Director approves an alternate completion for good cause; and

(iv) determine the integrity of the cement by a cement bond log.

(C) In order to provide the Commission with an opportunity to witness the setting and cementing of the surface casing and production casing (long string) and running of cement bond logs, the operator shall provide at least 15 days' notice to the appropriate Commission district office.

(D) Appropriate logs and other tests shall be conducted during the drilling and construction of a Class V spent brine return injection well to verify the depth to the top of the brine field, adequacy of cement behind the casing strings, and injectivity and fracture pressure of the brine field. A descriptive report interpreting the results of such logs and tests shall be prepared by a knowledgeable log analyst and submitted to the Director. The logs and tests appropriate to each well shall be determined based on the depth, construction, and other characteristics of the well, the availability of similar data in the area, and the need for additional information that may arise as the construction of the well progresses.

(E) The well shall be equipped with tubing and packer set within 100 feet of the top of the brine field.

(F) The wellhead shall be equipped with a pressure observation valve on the tubing and for each annulus of the well.

(G) Injection operations may not begin in any new Class V spent brine return injection well until the operator has submitted a completion report to the Director, and the Director has reviewed the completion report and found the well to be in compliance with this section and the conditions of the permit.

(5) Operating requirements. Class V spent brine return injection well permits will prescribe operating requirements, which shall at a minimum specify the following.

(A) All Class V spent brine return injection shall be into the same brine field from which the brine was extracted by the brine production wells.

(B) All injection shall be through tubing set on a packer. The packer shall be set within 100 feet of the top of the permitted injection interval. The Director will consider granting exceptions to this requirement for good cause and when the proposed completion of the well would still result in the protection of underground sources of drinking water and confinement of injected fluids. For wells that are approved for casing injection, the operator shall perform a casing pressure test against a temporary packer/plug to demonstrate mechanical integrity of the long string casing.

(C) Except during well stimulation, injection pressure at the wellhead shall not exceed the maximum pressure calculated to assure that the injection pressure does not initiate new fractures or propagate existing fractures in the brine field and in no case may the injection pressure initiate fractures in the confining zone or cause the escape of injection or formation fluids from the brine field.

(D) The operator shall fill the annulus between the tubing and long string casing with a corrosion inhibiting fluid. All injection wells shall maintain an annulus pressure sufficient to indicate mechanical integrity unless the Director determines that such requirement might harm the integrity of the well or endanger USDWs. The annulus pressure shall be monitored by a pressure chart or digital pressure gauge. The operator shall provide the Director with a written report and explanation of any change in annulus pressure that would indicate a leak or lack of mechanical integrity, such as an annulus pressure change exceeding 10%, within 15 days of detecting the change in pressure. An unsatisfactory explanation may result in a requirement that the well be tested for mechanical integrity.

(E) For each workover of an injection well, the operator shall notify the appropriate Commission district office at least 48 hours prior to the beginning of the workover or corrective maintenance operations that involve the removal of the tubing or well stimulation, and a mechanical integrity test shall be run on the well after the workover is completed if the packer is unseated during the workover.

(6) Corrective action. For all known wells in the area of review that penetrate the top of the brine field for which the operator cannot demonstrate proper completion, plugging, or abandonment, the Director will require corrective action if necessary to prevent movement of fluid into USDWs. Corrective action may be phased, if a phased corrective action plan has been approved by the Director.

(7) Mechanical integrity of Class V spent brine return injection wells.

(A) Mechanical integrity required. No person may perform injection operations in a Class V spent brine return injection well that lacks mechanical integrity. A well has mechanical integrity if:

(i) there is no significant leak in the casing (internal mechanical integrity); and

(ii) there is no significant fluid movement into a USDW through vertical channels adjacent to the wellbore (external mechanical integrity).

(B) Mechanical integrity shall be demonstrated to the satisfaction of the Director. In conducting and evaluating the results of a mechanical integrity test, the operator and the Director shall apply procedures and standards generally accepted in the industry. In reporting the results of a mechanical integrity test, the operator shall include a description of the method and procedures used. In evaluating the results, the Director will review monitoring and other test data submitted since the previous mechanical integrity test.

(C) Internal mechanical integrity. The permittee shall provide for a demonstration of internal mechanical integrity of the wellhead, casing, tubing, and annular seal assembly if present, using either a pressure test at a surface pressure of not less than 100 psig above the maximum expected operating surface pressure of the well or an equivalent test approved by the Director. The permittee shall provide a recording device to record the pressures measured during a mechanical integrity test.

(D) External mechanical integrity. The permittee shall use one of the following methods to demonstrate the absence of significant fluid movement into USDWs through vertical channels adjacent to the Class V spent brine return injection wellbore.

(i) the results of a temperature or noise log; or

(ii) where the nature of the casing precludes the use of the logging techniques prescribed in clause (i) of this subparagraph, cementing records demonstrating the presence of adequate cement to prevent such movement.

(E) Alternate methods. The Director may allow the use of a method of demonstrating mechanical integrity other than the methods listed in subparagraphs (C) and (D) of this paragraph with the approval of the administrator of EPA obtained pursuant to 40 CFR §146.8(d).

(F) Calibration of pressure gauges. A permittee shall calibrate all pressure gauges used in mechanical integrity demonstrations according to the manufacturer's recommendations. A copy of the calibration certificate shall be submitted to the Director at the time of demonstration and every time the gauge is calibrated. A pressure gauge shall have a resolution so as to allow detection of at least one-half of the maximum allowable pressure change.

(G) Timing of mechanical integrity testing.

(i) Both internal and external mechanical integrity shall be demonstrated before injection operations begin.

(ii) Internal mechanical integrity shall be demonstrated annually thereafter and after any workover that involves the removal of the tubing.

(iii) External mechanical integrity shall be demonstrated every five years.

(iv) The Director may require mechanical integrity testing if the Director has reason to believe that the well lacks mechanical integrity.

(H) Notice of testing.

(i) The permittee shall notify the appropriate Commission district office orally at least 48 hours before performance of a mechanical integrity test.

(ii) The permittee shall notify the Director in writing within 15 days of a failed mechanical integrity test. The notice shall indicate the permittee's plans for performing corrective action and re-testing the well or plugging the well.

(I) Reporting of testing. The permittee shall file a complete record of the test with the Commission in Austin within 30 days after the test. A copy of the pressure record shall accompany the report. The report shall include evaluation of the test results by a person qualified to provide such an evaluation. Reports of mechanical integrity demonstrations using downhole logs shall be accompanied by an interpretation of the log by a person qualified to make such interpretations.

(J) Failure to demonstrate mechanical integrity.

(i) A well shall maintain mechanical integrity. If the permittee or the Director finds that the well fails to demonstrate mechanical integrity during a test, fails to maintain mechanical integrity during operation, or that a loss of mechanical integrity is suspected during operation, the permittee shall halt injection immediately unless the Director allows continued injection because the permittee establishes that injection can continue without endangering USDWs. Report of the failure of mechanical integrity shall be made orally to the Director within 24 hours from the time the permittee becomes aware of the failure, and shall include an anticipated date for a mechanical integrity demonstration.

(ii) All wells that fail to pass a mechanical integrity test shall be repaired or plugged and abandoned within 90 days of the failure date. The 90-day timeline may be extended by the Director for good cause. The well is to be shut-in immediately after failure to pass the mechanical integrity test and shall remain shut-in until it passes a mechanical integrity test or is plugged and abandoned.

(iii) If injection has ceased as provided by clause (i) of this subparagraph, then the permittee shall not resume injection until the well demonstrates mechanical integrity. A written plan to restore mechanical integrity shall be submitted to the Director within 15 days of the failure of mechanical integrity. The plan shall include a schedule and description of corrective action and a schedule for re-testing or plugging the well. The plan shall be approved by the Director and the Director may witness any mechanical integrity demonstration.

(K) Testing deviations. The Commission will consider any deviations during testing that cannot be explained by factors such as temperature fluctuations or by the margin of error for the test used to determine mechanical integrity to be an indication of the possibility of a significant leak and/or the possibility of significant fluid movement into a formation containing a USDW through channels adjacent to the injection wellbore.

(8) Monitoring and records.

(A) Monitoring requirements. Permits shall specify the following monitoring requirements:

(i) the proper use, maintenance, and installation of monitoring equipment or methods;

(ii) the type, intervals, and frequency of monitoring sufficient to yield data representative of the monitored activity, including continuous monitoring when appropriate;

(iii) the reporting of monitoring results with a frequency dependent on the nature and effect of the monitored activity, but in no case less than annually; and

(iv) any samples and measurements taken for the purpose of monitoring shall be representative of the monitored activity.

(B) Record retention. The operator shall retain records of all monitoring information, including all calibration and maintenance records and all original chart recordings for continuous monitoring instrumentation, copies of all reports required by the permit, and records of all data used to complete the permit application, for at least three years from the date of the sample, measurement, report, or application. This period may be extended by request of the Commission at any time.

(C) Monitoring record contents. Records of monitoring information shall include the date, exact place, and time of the sampling or measurements; the individuals who performed the sampling or measurements; the dates analyses were performed; the individuals who performed the analyses; the analytical techniques or methods used for the analyses; and the results of the analyses.

(D) Signatory requirements. All reports and other information submitted to the Commission shall be signed and certified in accordance with subsection (c)(2) of this section.

(E) Reporting requirements.

(i) The operator shall notify the Commission and obtain Commission approval in advance of any planned changes to the brine production project, including any physical alternation or addition to the project and any change that may result in non-compliance with permit conditions.

(ii) Monitoring results shall be reported at the intervals specified in the permit.

(iii) Reports of compliance or noncompliance with the requirements contained in any schedule of compliance shall be submitted no later than 30 days after each scheduled date.

(iv) The operator shall report to the Commission any noncompliance that may endanger USDWs, human health, or the environment.

(I) An oral report shall be made to the appropriate Commission district office immediately after the operator becomes aware of the noncompliance.

(II) A written report shall be filed with the Director within five days of the time the operator becomes aware of the noncompliance. The written report shall contain the following information:

(-a-) a description of the noncompliance and its cause;

(-b-) the period of noncompliance, including exact dates and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue; and

(-c-) steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance.

(v) Information that shall be reported under this subparagraph includes the following:

(I) any monitoring or any other information that indicates that any contaminant may endanger USDWs; and

(II) any noncompliance with a permit condition or malfunction of the injection system that may cause fluid migration into or between USDWs.

(F) Reporting errors. If the operator becomes aware that it failed to submit any relevant facts or report any noncompliance, or that it submitted incorrect information in a permit application or a report to the Director, then the operator shall promptly submit the relevant facts, report of noncompliance, or correct information as applicable. A report of noncompliance shall contain the information listed in subparagraph (E) of this paragraph.

(9) Notice of workovers. The operator shall notify the appropriate Commission district office at least 48 hours before performing any workover or corrective maintenance operations that involve the unseating of the packer or well stimulation.

(10) Additional conditions. The Commission may establish additional conditions on a case-by-case basis as required to provide for and assure compliance with the requirements specified in this section.

(k) Violations; penalties.

(1) Any well drilled or operated in violation of this section without a permit issued under this section shall be plugged.

(2) Violations of this section may subject the operator to penalties and remedies specified in the Texas Water Code, Chapter 27, and the Natural Resources Code, Title 3.

(3) The certificate of compliance for a brine production well may be revoked in the manner provided in subsections §3.73(d)-(g), (i)-(k) of this title (relating to Pipeline Connection; Cancellation of Certification of Compliance; Severance) for violations of this section.

(l) Commission review of administrative actions. Administrative actions performed by the Director or Commission staff pursuant to this section are subject to review by the commissioners.

(m) Federal regulations. All references to the CFR in this section are references to the 1987 edition of the Code. The following federal regulations are adopted by reference and can be obtained at the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78711: 40 CFR §§124.8(b), 124.10(c)(1)(viii), 124.10(d), and 146.8(d). Where the word "director" is used in the adopted federal regulations, it should be interpreted to mean "commission."

(n) Effective date. For the regulations pertaining to Class V spent brine return injection wells, this section becomes effective upon approval of the Commission's Class V Underground Injection Control (UIC) Program for spent brine return injection wells by the USEPA under the Safe Drinking Water Act, §1422 (42 United States Code §300h-1). For all other regulations, this section becomes effective as provided in Section 2001.001 et seq. of the Texas Government Code.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on October 15, 2024.

TRD-202404850

Haley Cochran

Assistant General Counsel, Office of the General Counsel

Railroad Commission of Texas

Earliest possible date of adoption: December 1, 2024

For further information, please call: (512) 475-1295