Geologic Storage of Carbon Dioxide (CO2)

UIC Class VI & Primacy

Effective January 10, 2011, the US Environmental Protection Agency (EPA) promulgated Underground Injection Control (UIC) regulations for a new UIC Class VI program regulating the geologic sequestration of anthropogenic carbon dioxide (CO2). The federal requirements for the UIC Class VI program are more complex than the requirements for the Class II program. With respect to the difference between UIC Class II and Class VI, the greatest influence on risk is the injection pressure and volume.

The Texas Legislature established a framework for geologic storage of anthropogenic CO2 in Texas in 2009 to adopt regulations consistent with federal regulations and to seek federal enforcement primacy for the program. In 2021, the statute was amended to consolidate state jurisdiction for the Class VI program under the Railroad Commission of Texas ("RRC"). Consolidation of the Class VI program into one agency will greatly ease US Environmental Protection Agency's ("EPA") process for review of the state’s application for enforcement primacy.

RRC adopted regulations on December 10, 2010, and amended on September 19, 2022, Texas Administrative Code (TAC), Part 1, Title 16, Chapter 5. Interest in CO2 sequestration until recently has been limited to storage associated with Class II enhanced oil recovery (EOR) injection wells. Carbon dioxide storage incidental to EOR is a Class II activity and, therefore, may be permitted under the RRC's Statewide Rule 46. However, since the revisions to federal incentives under Section 45Q of the Internal Revenue Code, RRC has seen increasing interest in Class VI geologic storage unrelated to EOR.

Staff adopted amendments to Chapter 5 – Carbon Dioxide – to meet the federal Class VI UIC requirements which are required to receive primary enforcement authority ("primacy") from EPA. The State submitted its official application for primacy on December 19, 2022. US EPA has reviewed the application for completeness. RRC is currently amending its rules to ensure that the application meets the minimum federal requirements. Staff submitted the final rules to EPA for review in August 2023.

Staff have been coordinating with EPA and other states with primacy (North Dakota and Wyoming) as well as states that are in the process (Louisiana) through the Ground Water Protection Council’s (GWPC’s) working group to gain knowledge of these states’ experience during the primacy application process.

Geologic Information for a CO2 Storage Project

Stratigraphic Test Wells

A drilling permit is required for an oil and gas operator in Texas to drill a test well or a monitoring well (that penetrates the base of usable-quality water).

An operator under RRC jurisdiction does not need an injection permit to drill a test well and perform geologic or well testing if those tests are typical for oil and gas exploration. See 16 TAC §5.102 (49): Stratigraphic test well--An exploratory well drilled for the purpose of gathering information in connection with a proposed carbon dioxide geologic storage project, including formation testing to obtain information on the chemical and physical characteristics of the injection zones and confining zones. Such testing may include injectivity testing.

Monitoring Wells

An operator under RRC jurisdiction does not need an injection permit to drill, complete and monitor a monitor well. However, the Commission's rules, especially 16 TAC, Chapter 3, "Oil and Gas Division", apply and must be followed. Monitor wells for CO2 geologic storage facilities may have special requirements which can be addressed in the Class VI permit application.

How to Become a Class VI Well

Until RRC receives UIC Class VI primary enforcement authority, you must receive a UIC Class VI permit from EPA to inject and store anthropogenic CO2. These guidelines only apply to the process for receiving a permit from RRC. EPA may have different or additional requirements. Please contact US EPA Region 6 for more information.

An operator must complete each of the following steps before beginning geologic storage of anthropogenic CO2, 16 TAC §5.202 (a)(2):

  1. Geologic Storage Facility Permit: You must submit an application for and receive a geologic storage facility permit under 16 TAC Ch. 5, Subch. B – Geologic Storage and Associated Injection of Anthropogenic Carbon Dioxide (CO2) [Note: you may not apply for a permit unless you have an active Organization Report (Form P-5)];
  2. Permit to Drill: After you’ve received your geologic storage facility permit, you must submit an application (Form W-1)  for and receive a permit to drill, deepen, or convert the well for geologic storage;
  3. You must drill and complete the well;
  4. Notice of Completion and Completion Report: You must submit a notice of completion of construction to the Oil and Gas Director or their delegate and submit a completion report (Form W-2/G-1) to RRC Online;
  5. Inspection: An RRC inspector must inspect the injection well and find that it is in compliance with the conditions of the permit; and
  6. Permit to Operate: The Oil and Gas Director or their delegate must have issued a permit to operate the injection well.

New Class VI Well

Submit an application for a permit for a geologic storage facility for anthropogenic CO2 and complete the rest of the steps outlined above.

New Stratigraphic Test Well

You must have a Permit to Drill (Form W-1) prior to drilling the stratigraphic test well and file a completion report (Form W-2/G-1) once the well is completed. Subsequently, you must submit an application for a permit for a geologic storage facility for anthropogenic CO2 and, after approval, complete the rest of the steps outlined above, including re-completion of the existing stratigraphic test well for geologic storage. A permit will only be approved if the well construction meets all the UIC Class VI requirements. You may follow the UIC Class VI Strat Test Well Construction Verification procedure to ensure that your conversion to a Class VI well is expedient and without issue.

Recomplete Existing O&G Well or Injection Well

Request a permit for geologic storage and, after approval, complete the rest of the steps outlined above, including re-completion of an existing O&G well, injection well or beginning geologic storage of anthropogenic CO2 in a previously permitted injection well [for example, CO2 EOR or Acid Gas Disposal well(s)]. A permit will only be approved if the well construction meets all of the UIC Class VI requirements. Be advised that most O&G wells and O&G injection wells (UIC Class II) will not meet these requirements, and that P&A’d UIC Class I wells are prohibited by law from receiving a UIC Class VI permit. It is recommended that you contact the Injection-Storage Permits Unit at UIC@rrc.texas.gov before beginning a project to convert an existing oil and gas well or injection well.

Commission-Required Class VI Permit

RRC may make a determination that operation of your Class II injection well [CO2 EOR or Acid Gas Disposal well(s)] is no longer for the primary purpose of enhanced recovery operations or has increased risk to USDWs and the well(s) must be converted to a Class VI permit, 16 TAC §5.201 (b)(2).

UIC Class VI Strat Test Well Construction Verification

A UIC Class VI Strat Test Well is a well drilled for the purpose of collecting in-situ geologic data and will be completed as a UIC Class VI injection well. Although not required, you may follow the steps below so that RRC staff can verify that the well construction and completion will meet UIC Class VI injection well rule requirements:

  1. Submit a letter of intent to UIC@rrc.texas.gov to apply for a drilling permit for a stratigraphic test well to be converted to UIC Class VI well.
    1. The letter should include all information necessary for RRC staff to determine that the well will be constructed in accordance with 16 TAC §5.203 (e), but must include at a minimum:
      1. A draft Completion Report (Form W-2/G-1)
      2. Wellbore Diagram
      3. Well completion specifications to demonstrate CO2 resistance
  2. RRC staff will review the letter and respond within approximately 30 days. Staff will provide a letter stating either that:
    1. The proposed completion meets the requirements and you may apply for a drilling permit, or
    2. The proposed completion does not meet the requirements and the deficiencies in the proposal.
  3. After receiving a drilling permit and drilling and completing the well, you must submit a Completion Report as required by 16 TAC §3.15. To facilitate staff’s review, you should attach staff’s UIC Class VI Strat Test Well approval letter to the completion report and send an email to UIC@rrc.texas.gov to notify RRC staff that the well completion report has been filed.

Permit Applications

Until RRC receives Class VI primacy, any applicant for geologic storage of anthropogenic CO2 unrelated to Enhanced Oil Recovery (EOR) will need to submit an application to both EPA and the RRC. However, RRC staff have been coordinating with EPA to ensure that both agencies perform the application review on a parallel track, using the EPA Geologic Storage Data Tool (GSDT) so that when the RRC receives primacy, the transfer will be as seamless as possible.

RRC's permit application requirements can be found in 16 TAC §5.203. A permit application to drill and operate a geologic storage facility for CO2 will include, but is not limited to, the following components:

  • Fees, (for example, $50,000 for a new geologic storage facility)
  • Project Narrative & Site Characterization
  • Pre-Operational Testing Plan
  • Well Construction Plan
  • Well Stimulation Plan
  • Operating Plan
  • Area of Review (AOR) & Corrective Action Plan (CAP)
  • Testing & Monitoring Plan (incl. MIT)
  • Quality Assurance and Surveillance Plan (incl. seismicity)
  • Well Plugging Plan
  • Emergency & Remedial Response Plan
  • Post-Injection Site Care (PISC) & Site Closure Plan
  • Financial Assurance & Responsibility Demonstration
  • Freshwater "No Harm" Letter from RRC's Groundwater Advisory Unit
  • Class I "No Harm" Letter from the Texas Commission on Environmental Quality (TCEQ)
  • Environmental Justice (EJ) or Limited English-Speaking Community Assessment & Plan

Permit applications must be prepared by qualified professionals. Parts of the application must be signed and sealed by professional geoscientists and/or engineers licensed in Texas (for example, AOR & CAP and Closure Cost Estimate). If you are developing a project and application, you are encouraged to contact RRC staff prior to submitting your application. Your application must be submitted to the EPA Geologic Storage Data Tool (GSDT). Some of the application components may have many parts, so applicants are encouraged to use EPA's permit application templates to facilitate staff review. 

CO2 EOR Permit Applications

An applicant for geologic storage of anthropogenic CO2 incidental to EOR may submit an Application to Inject Fluid into a Productive Reservoir (Form H-1/H-1A). Additionally, an applicant may be entitled to a reduced state severance tax rate under Statewide Rule 50 - Enhanced Oil Recovery Projects and further reduced tax rate for storage anthropogenic CO2.

Confidential Materials

All records, data, and information filed with the Commission are subject to the Texas Public Information Act, Texas Government Code, Chapter 552. If the Commission receives a third-party request for materials that have been marked confidential, the Commission will notify the filing party of the request in accordance with the provisions of the Texas Public Information Act so that the party can take action with the Office of the Attorney General to oppose release of the materials.

The designation of material as confidential is frequently carried to excess. The Commission has a responsibility to provide a copy of each application to interested persons upon request and to safeguard confidential material from becoming public knowledge. Thus, RRC staff request that the applicant be prudent in the designation of material as confidential and submit confidential material only when it is required or likely to be necessary for the Commission to make a decision on the permit application.

To file materials you contend to be confidential by law you must deliver the materials in a sealed and labeled container accompanied by an explanatory cover letter. The outside of the container shall identify the name of the submitting party and be marked "CONFIDENTIAL AND UNDER SEAL" in bold print at least one inch in size. The front page of each portion of confidential material shall be marked "confidential." The cover letter shall explain the nature of the sealed materials and the applicable legal theory for why the information is confidential under state law. The cover letter will not be considered confidential and may be filed in a publicly accessible format or released to the public if requested.

Electronic Submission

Electronic documents must be submitted with the same labels and cover letter as described above. If the confidential material is submitted via email, the subject and body of the email must include the term "CONFIDENTIAL" in capital letters. You must notify RRC staff before submitting confidential materials electronically.

EPA's Geologic Sequestration Data Tool (GSDT) is capable of receiving confidential material. Material submitted to the GSDT as confidential will be considered confidential by RRC staff and handled in accordance with the procedure described in the first paragraph of this section. 

Redacted Copy

Many applicants have chosen to provide a confidential copy of the permit application for geologic storage of CO2 and a redacted copy which may be distributed to the public. Commission staff encourages applicants for a geologic storage facilities to provide a copy of the permit application that can be made publicly available. Please ensure that the confidential information is fully redacted since staff is not responsible for quality assuring redactions made by the applicant.

Waste Disposal

Waste arising from or incidental to a Class VI well is the jurisdiction of RRC and must be disposed of in an authorized manner. Non-hazardous solid wastes from a Class VI operation may be disposed of at RRC surface disposal facilities by requesting a letter of authority from RRC's Environmental Permits Unit in Austin. Liquid wastes cannot be authorized for disposal into a Class II oil and gas disposal well (16 TAC §3.9 or §3.46), because the waste is not related to oil and gas activities.

Acid Gas Disposal Wells with CO2

Acid gas disposal wells can continue to be permitted as Class II wells when the fluid is generated from oil and gas activities from a single lease, unit, field, or gas processing facility. It is understood that the CO2 thus injected is essentially sequestered if the injection meets the UIC requirement that the CO2 is confined in the permitted injection interval. Therefore, geologic storage of CO2 can continue to be permitted under the UIC Class II program under these limited circumstances.

Acid gas disposal well operations that are focused on oil or gas production will be managed under the Class II program. If acid gas disposal associated with an oil or gas lease, unit, field or gas processing facility is no longer a significant aspect of a Class II permitted operation, the key factor in determining the potential need to transition an acid gas disposal well from Class II to Class VI is the increased risk to Underground Sources of Drinking Water (USDWs) related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class II program. However, transition to Class VI will be considered if the Class II tools are insufficient to manage the increased risk.

In determining if there is an increased risk to USDWs, the director will consider the following factors:

  • increase in reservoir pressure within the injection zone;
  • increase in CO2 injection rates;
  • distance between the injection zone and USDWs;
  • suitability of the enhanced oil or gas recovery AOR delineation;
  • quality of abandoned well plugs within the AOR;
  • the storage operator's plan for recovery of CO2 at the cessation of injection;
  • the source and properties of injected CO2; and
  • any additional site-specific factors as determined by the Commission.

Class II and Class VI directors will work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director will have the relevant data on pressure and volume of CO2 injected into Class II acid gas disposal wells, which will influence any transition decision.

Acid Gas Disposal Wells with CO2 Permit Procedures

To ensure that Class II acid gas disposal wells with CO2 are properly permitted, the following UIC permitting procedures will be followed:

  • Any disposal permit application with CO2 as an injection fluid will be reviewed by the Chief Geologist or their delegate.
  • The applicant must submit CO2 source data in the permit application to ensure the well’s CO2 source is focused on oil and gas production.
  • The applicant should submit information regarding the well construction materials and any other precautions taken for injection of CO2.
  • Staff will evaluate the proposed injection volumes and pressures to ensure there is no increased risk to USDWs (e.g. to ensure an appropriate AOR distance).
    • Staff may require reservoir simulation to model the plume and pressure and to identify any additional relevant artificial penetrations for this review (for example, modeling may be requested when the proposed injection rate is greater than 10 MMCFD).
  • Acid gas disposal well permits will include a permit condition that states that the acid gas permit is not Class VI authority.
  • Permits may include the following conditions:
    • Annual tubing-casing annulus pressure test MIT and weekly tubing-casing annulus monitoring,
    • On-going pressure monitoring for increased risk to USDW, for example:
      • Initial and annual or 5-year bottom-hole pressure tests,
      • Reservoir pressure analysis,
      • Annual reporting of reservoir fluid migration and pressure monitoring, and
    • Notification if an event occurs that jeopardizes the mechanical and/or hydraulic integrity of any segment of the processing, injection or storage components of the permitted facility.
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