Texas Administrative Code, Title 16: Economic Regulation, Part 1: Texas Railroad Commission, Chapter 5: Carbon Dioxide (Texas CO2 Code)

Jurisdiction(s)
Instrument Date
Effective Date
Instrument Type
Relevant Regulatory Authority
Railroad Commission of Texas
Purpose and Context
The purpose of the Texas CO2 Code, as stated in §5.101, is “to implement the portion of the state program for geologic storage of anthropogenic CO2 over which the Railroad Commission has jurisdiction consistent with state and federal law related to protection of underground sources of drinking water.” In addition, Subchapter C of the Code provides for the certification of permanent CO2 storage in enhanced oil recovery operations.
Relevant links
Instrument Access Date
1 October 2012
I. Regulatory scope and definitions
Definitions

Article/Section No.

§5.102

Instrument Text

RULE §5.102 Definitions

The following terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.
(1) Affected person--A person who, as a result of actions proposed by an application for a geologic storage facility permit or an amendment or modification of an existing geologic storage facility permit, has suffered or may suffer actual injury or economic damage other than as a member of the general public.

(2) Anthropogenic carbon dioxide (CO 2 )--

(A) CO2 that would otherwise have been released into the atmosphere that has been:

(i) separated from any other fluid stream; or

(ii) captured from an emissions source, including:

(I) an advanced clean energy project as defined by Health and Safety Code, §382.003, or another type of electric generation facility; or

(II) an industrial source of emissions; and

(iii) any incidental associated substance derived from the source material for, or from the process of capturing, CO2 described by clause (i) of this subparagraph; and

(iv) any substance added to CO2 described by clause (i) of this subparagraph to enable or improve the process of injecting the CO2 ; and

(B) does not include naturally occurring CO2 that is produced, acquired, recaptured, recycled, and reinjected as part of enhanced recovery operations.

(3) Anthropogenic CO2 injection well--An injection well used to inject or transmit anthropogenic CO2 into a reservoir.

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

(5) Area of review--The subsurface three-dimensional extent of the CO2 stream plume and the associated pressure front, as well as the overlying formations, any underground sources of drinking water overlying an injection zone along with any intervening formations, and the surface area above that delineated region.

(6) Carbon dioxide (CO2 ) plume--The underground extent, in three dimensions, of an injected CO2 stream.

(7) Carbon dioxide (CO2 ) stream--CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. The term does not include any CO2 stream that meets the definition of a hazardous waste under 40 Code of Federal Regulations Part 261.

(8) Commission--A quorum of the members of the Railroad Commission of Texas convening as a body in open meeting.

(9) Confining zone--A geologic formation, group of formations, or part of a formation that is capable of limiting fluid movement from an injection zone.

(10) Corrective action--Methods to assure that wells within the area of review do not serve as conduits for the movement of fluids into or between underground sources of drinking water, including the use of corrosion resistant materials, where appropriate.

(11) Delegate--The person authorized by the director to take action on behalf of the Railroad Commission of Texas under this chapter.

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

(13) Division--The Oil and Gas Division of the Railroad Commission of Texas.

(14) Enhanced recovery operation--Using any process to displace hydrocarbons from a reservoir other than by primary recovery, including using any physical, chemical, thermal, or biological process and any co-production project. This term does not include pressure maintenance or disposal projects.

(15) Facility closure--The point at which the operator of a geologic storage facility is released from post-injection storage facility care responsibilities.

(16) Formation fluid--Fluid present in a formation under natural conditions.

(17) Fracture pressure--The pressure that, if applied to a subsurface formation, would cause that formation to physically fracture.

(18) Geologic storage--The long-term containment of anthropogenic CO2 in a reservoir.

(19) Geologic storage facility or storage facility--The underground reservoir, underground equipment, injection wells, and surface buildings and equipment used or to be used for the geologic storage of anthropogenic CO2 and all surface and subsurface rights and appurtenances necessary to the operation of a facility for the geologic storage of anthropogenic CO2 . The term includes any reasonable and necessary areal buffer, subsurface monitoring zones, and pressure fronts. The term does not include a pipeline used to transport CO2 from the facility at which the CO2 is captured to the geologic storage facility. The storage of CO2 incidental to or as part of enhanced recovery operations does not in itself automatically render a facility a geologic storage facility.

(20) Injection zone--A geologic formation, group of formations, or part of a formation that is of sufficient areal extent, thickness, porosity, and permeability to receive CO 2 through a well or wells associated with a geologic storage facility.

(21) Mechanical integrity--

(A) An anthropogenic CO2 injection well has mechanical integrity if:

(i) there is no significant leak in the casing, tubing, or packer; and

(ii) there is no significant fluid movement into a stratum containing an underground source of drinking water through channels adjacent to the injection well bore as a result of operation of the injection well.

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

(22) Monitoring well--A well either completed or re-completed to observe subsurface phenomena, including the presence of anthropogenic CO2 , pressure fluctuations, fluid levels and flow, temperature, and/or in situ water chemistry.

(23) Operator--A person, acting for himself or as an agent for others, designated to the Railroad Commission of Texas as the person with responsibility for complying with the rules and regulations regarding the permitting, physical operation, closure, and post-closure care of a geologic storage facility, or such person's authorized representative.

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

(25) Post-injection facility care--Monitoring and other actions (including corrective action) needed following cessation of injection to assure that underground sources of drinking water are not endangered and that the anthropogenic CO2 remains confined to the permitted injection interval.

(26) Pressure front--The zone of elevated pressure that is created by the injection of the CO2 stream into the subsurface where there is a pressure differential sufficient to cause movement of the CO2 stream or formation fluids from the injection zone into an underground source of drinking water.

(27) Reservoir--A natural or artificially created subsurface sedimentary stratum, formation, aquifer, cavity, void, or coal seam.

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

(29) Underground source of drinking water--An aquifer or its portion which is not an exempt aquifer as defined in 40 Code of Federal Regulations §146.4 and which:

(A) supplies any public water system; or

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

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

(ii) contains fewer than 10,000 mg/l total dissolved solids.

(30) Well stimulation--Any of several processes used to clean the well bore, enlarge channels, and increase pore space in the interval to be injected thus making it possible for fluid to move more readily into the formation including, but not limited to, surging, jetting, blasting, acidizing, and hydraulic fracturing.

(31) 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 chapter, workovers do not include well stimulation operations.

 

Classification of CO2

Summary

The definition of “carbon dioxide (CO2) stream” given in §5.102 of the Texas CO2 Code expressly excludes CO2 streams that meet the definition of a hazardous waste under 40 Code of Federal Regulations Part 261. 

Article/Section No.

§5.102

Instrument Text

RULE §5.102 Definitions

The following terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.
[…]
(7) Carbon dioxide (CO2 ) stream--CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. The term does not include any CO2 stream that meets the definition of a hazardous waste under 40 Code of Federal Regulations Part 261.

Composition of CO2 stream

Summary

§5.102 of the Texas CO2 Code defines a CO2 stream as “CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process.”

 

CO2 streams that meet the definition of a hazardous waste under Code of Federal Regulations Title 40 Part 261 are expressly excluded from this definition. 

Article/Section No.

§5.102

Instrument Text

RULE §5.102 Definitions

The following terms, when used in this chapter, shall have the following meanings, unless the context clearly indicates otherwise.
[…]
(2) Anthropogenic carbon dioxide (CO 2 )--

(A) CO2 that would otherwise have been released into the atmosphere that has been:

(i) separated from any other fluid stream; or

(ii) captured from an emissions source, including:

(I) an advanced clean energy project as defined by Health and Safety Code, §382.003, or another type of electric generation facility; or

(II) an industrial source of emissions; and

(iii) any incidental associated substance derived from the source material for, or from the process of capturing, CO2 described by clause (i) of this subparagraph; and

(iv) any substance added to CO2 described by clause (i) of this subparagraph to enable or improve the process of injecting the CO2 ; and

(B) does not include naturally occurring CO2 that is produced, acquired, recaptured, recycled, and reinjected as part of enhanced recovery operations.

[…]

(7) Carbon dioxide (CO2 ) stream--CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. The term does not include any CO2 stream that meets the definition of a hazardous waste under 40 Code of Federal Regulations Part 261.

Geographical coverage, exclusions and prohibitions

Summary

Subchapter B of the Code is expressed, in §5.201, to apply to the geologic storage of anthropogenic CO2, and to exclude naturally occurring CO2 forming part of enhanced recovery operations. Certification of permanent CO2 storage in such operations is addressed separately in Subchapter C.

Article/Section No.

§5.201

Instrument Text

RULE §5.201 Applicability and Compliance

(a) This subchapter applies to the geologic storage of anthropogenic CO2 in, and the injection of anthropogenic CO2 into, a reservoir that is initially or may be productive of oil, gas, or geothermal resources or a saline formation directly above or below that reservoir. A reservoir that may be productive means an identifiable geologic unit that has had production in the past, which is similar to productive or previously productive reservoirs along the same or a similar trend, or potentially contains oil, gas, or geothermal resources based on analysis of geophysical and/or seismic data.

(b) This subchapter does not apply to the injection of fluid through the use of an injection well regulated under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) for the primary purpose of enhanced recovery operations from which there is reasonable expectation of more than insignificant future production volumes of oil, gas, or geothermal energy and operating pressures are no higher than reasonably necessary to produce such volumes or rates. However, the operator of an enhanced recovery project may propose to also permit the enhanced recovery project as a CO2 geologic storage facility simultaneously. If the director determines that an injection well regulated under §3.46 of this title should be regulated under this subchapter because the injection well is no longer being used for the primary purpose of enhanced recovery operations, the director must notify the operator of such determination and allow the operator at least 30 days to respond to the determination and to file an application under this subchapter or cease operation of the well. Additionally, this subchapter does not preclude an enhanced oil recovery project operator from opting into a regulatory program that provides carbon credit for anthropogenic CO2 sequestered through the enhanced recovery project.

(c) This subchapter applies to a well that is authorized as or converted to an anthropogenic CO2 injection well for geologic storage.

(d) If a provision of this subchapter conflicts with any provision or term of a Commission order or permit, the provision of such order or permit controls.

(e) The operator of a geologic storage facility must comply with the requirements of this subchapter as well as with all other applicable Commission rules and orders, including the requirements of Chapter 8 of this title (relating to Pipeline Safety Regulations) for pipelines and associated facilities.

Enhanced oil recovery (EOR)

Summary

Subchapter B of the Texas CO2 Code is expressed in §5.101 to apply to the geologic storage of anthropogenic CO2, which is in turn defined in §5.102 to exclude naturally occurring CO2 forming part of EOR operations.

 

However, under §5.201(b) operators of EOR projects may propose to simultaneously permit enhanced recovery projects as CO2 storage facilities.

 

In addition, if the Director of the Oil and Gas Division of the Texas Railroad Commission determines that an EOR injection well should be regulated under Subchapter B because the well is no longer used primarily for EOR, the Director must notify the operator of such determination and allow the operator at least 30 days to respond and either to make an application under Subchapter B or cease operation of the well.

 

§5.201(b) goes on to state that Subchapter B of the Code does not preclude EOR operators from opting into regulatory programs that provide carbon credits for sequestration of anthropogenic CO2 through EOR projects.

 

Subchapter C of the Code expressly addresses CO2 injection and storage in EOR processes, establishing specific certification requirements where the operator wishes to document that CO2 (whether anthropogenic or naturally occurring) is permanently stored. These provisions encompass, among other things, dedicated monitoring, reporting and fee requirements.

Article/Section No.

§5.101
§5.102
§5.201(b)
§5.301
§5.302
§5.303
§5.304
§5.305
§5.306
§5.307
§5.308

Instrument Text

RULE §5.101 Purpose

The purpose of this chapter is to implement the portion of the state program for geologic storage of anthropogenic CO2 over which the Railroad Commission has jurisdiction consistent with state and federal law related to protection of underground sources of drinking water.
[…]
RULE §5.102 Definitions

[…]
(2) Anthropogenic carbon dioxide (CO 2 )--

(A) CO2 that would otherwise have been released into the atmosphere that has been:

(i) separated from any other fluid stream; or

(ii) captured from an emissions source, including:

(I) an advanced clean energy project as defined by Health and Safety Code, §382.003, or another type of electric generation facility; or

(II) an industrial source of emissions; and

(iii) any incidental associated substance derived from the source material for, or from the process of capturing, CO2 described by clause (i) of this subparagraph; and

(iv) any substance added to CO2 described by clause (i) of this subparagraph to enable or improve the process of injecting the CO2 ; and

(B) does not include naturally occurring CO2 that is produced, acquired, recaptured, recycled, and reinjected as part of enhanced recovery operations.
[…]

RULE §5.201 Applicability and Compliance


(b) This subchapter does not apply to the injection of fluid through the use of an injection well regulated under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) for the primary purpose of enhanced recovery operations from which there is reasonable expectation of more than insignificant future production volumes of oil, gas, or geothermal energy and operating pressures are no higher than reasonably necessary to produce such volumes or rates. However, the operator of an enhanced recovery project may propose to also permit the enhanced recovery project as a CO2 geologic storage facility simultaneously. If the director determines that an injection well regulated under §3.46 of this title should be regulated under this subchapter because the injection well is no longer being used for the primary purpose of enhanced recovery operations, the director must notify the operator of such determination and allow the operator at least 30 days to respond to the determination and to file an application under this subchapter or cease operation of the well. Additionally, this subchapter does not preclude an enhanced oil recovery project operator from opting into a regulatory program that provides carbon credit for anthropogenic CO2 sequestered through the enhanced recovery project.
[…]

RULE §5.301 Applicability

(a) This subchapter establishes the requirements for certification of the injection, and incidental storage, of anthropogenic CO2 into productive reservoirs for the purpose of enhanced recovery of oil, gas, or geothermal resources, and for which the operator requests certification from the Commission that the anthropogenic CO2 is permanently stored.

(b) This subchapter applies to the injection of anthropogenic CO2 in a reservoir in connection with enhanced recovery for which:

(1) there is a reasonable expectation of more than insignificant future production of oil, gas, or geothermal volumes or rates as a result of the injection of CO2 ; and

(2) using operating pressures not anticipated to be higher than reasonably necessary to produce such production of oil, gas, or geothermal volumes and rates are covered by this rule, and the wells used in such enhanced recovery continue to be covered in accordance with the requirements of §3.46 of this title (relating to Fluid Injection into Productive Reservoirs).

(c) For the purposes of this subsection, the CO2 stream injected into a productive reservoir may include any proportion of anthropogenic CO2 and naturally sourced CO2 .

(d) The operator of an enhanced recovery facility registering for certification of geologic storage of anthropogenic CO2 incidental to enhanced recovery operations is subject to the monitoring provisions of this subchapter.

(e) No permit is required for an operator to register with, or obtain a certification from, the Commission for geologic storage of anthropogenic CO2 incidental to enhanced recovery under this subchapter. Registration for certification by an operator under this subchapter is separate and distinct from an application for a Geologic Storage Facility under Subchapter B of this chapter (relating to Geologic Storage and Associated Injection of Anthropogenic Carbon Dioxide (CO2 )). The wells into which CO2 is injected for the purpose of enhanced recovery continue to be covered by §3.46 of this title.

(f) Registration under this subchapter is voluntary. An enhanced recovery facility may register under this subchapter to account for geologic sequestration of anthropogenic CO2 . Additionally, this subchapter does not preclude the operator of an enhanced recovery project from opting into a regulatory program that provides carbon credit for the geologic storage of anthropogenic CO2 incidental to enhanced recovery.

(g) An enhanced recovery facility subject to this subchapter includes all structures associated with injection and production located between the injection/production wells and the separators, but does not include the following:

(1) storage of CO2 above ground;

(2) temporary storage of CO2 below ground;

(3) transportation or distribution of CO2 ;

(4) purification, compression, or processing of CO2 at the surface;

(5) capture of CO2 ; or

(6) CO2 in cement, precipitated calcium carbonate, or any other technique that does not involve injection of CO2 into the subsurface.

(h) Conflict with other requirements. If a provision of this section conflicts with any provision or term of a Commission order, field rule, or permit, the provision of such order, field rule, or permit controls.
RULE §5.302 Definitions
The following words and terms, when used in this subchapter, shall have the following meanings, unless the context clearly indicates otherwise.
(1) Anthropogenic carbon dioxide (CO 2 )--Anthropogenic CO2 as defined in the Texas Water Code, §27.002(19)(A). The term does not include naturally occurring CO2 that is produced, acquired, recaptured, recycled, and reinjected as part of enhanced recovery. The use of the term "CO2 " in this subchapter includes anthropogenic CO2 .

(2) Anthropogenic CO2 stream--CO2 that has been captured from an emission source, incidental associated substances derived from the source materials and the capture process, and any substances added to the stream to enable or improve the injection process. The term does not include any CO2 stream that meets the definition of a hazardous waste under 40 Code of Federal Regulations Part 261.

(3) CO2 injection well--An injection well used to inject or transmit CO2 into an enhanced recovery reservoir.

(4) Certification--As used in this subchapter, a document issued annually by the director validating the geologic storage of anthropogenic CO2 incidental to enhanced recovery at a facility registered under this subchapter.

(5) Enhanced recovery--Any process to displace hydrocarbons from a reservoir other than by primary recovery, including using any physical, chemical, thermal, or biological process and any co-production project. This term does not include pressure maintenance or disposal projects.

(6) Enhanced recovery facility--The underground reservoir, underground equipment, injection wells, and surface buildings and equipment and all surface and subsurface rights and appurtenances necessary to an enhanced recovery operation.

(7) Geologic storage--The incidental underground storage of CO2 in a productive reservoir that occurs incidental to enhanced recovery.

(8) Productive reservoir--A reservoir that is productive of oil, gas and geothermal resources and for which:

(A) there is a reasonable expectation of more than insignificant future production of oil, gas or geothermal volumes or rates as a result of the injection of CO2 ; and

(B) using operating pressures not anticipated to be higher than reasonably necessary to produce such production of oil, gas or geothermal volumes and rates.
RULE §5.303 Registration for Certification

(a) The operator or the proposed operator of an enhanced recovery facility for which the operator proposes to document geologic storage of anthropogenic CO2 incidental to enhanced recovery must register with the Commission in Austin.

(1) The operator or proposed operator must include the prescribed fee with the registration application and must ensure that the registration application is executed by a party having knowledge of the facts entered on the registration.

(2) The operator or proposed operator must include with the registration application the following:

(A) the name, mailing address, and location of the facility for which the application is being submitted and the operator's name, address, telephone number, Commission Organization Report number, and ownership of the facility;

(B) a demonstration that the reservoir is undergoing enhanced recovery using injection of anthropogenic CO2 , including:

(i) the Commission field designation;

(ii) the Commission order approving such enhanced recovery project and a plat of the designated area;

(iii) a list of all injection wells permitted under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) within the enhanced recovery facility; and

(iv) information regarding the period of time for which CO2 injection has been conducted, or is expected to be conducted, together with the total anticipated volume of anthropogenic CO2 to be injected; and

(C) a testing, monitoring, and reporting plan.

(b) Within 90 days of receipt of a complete registration application, the director will approve or deny the registration application. If the director approves the registration application, the acknowledgment will include the conditions for certification, including conditions for monitoring and reporting.
RULE §5.304 Fees

The operator or proposed operator must remit the following non-refundable fees to the Commission with each registration application under this subchapter:
(1) a non-refundable fee of $500 for each enhanced recovery facility to be registered; and

(2) annually, a non-refundable certification fee of $10,000 for each enhanced recovery facility registered under this subchapter.

RULE §5.305 Monitoring, Sampling, and Testing Plan

An operator registering for certification under this subchapter must submit a monitoring, sampling, and testing plan to verify geologic storage of the anthropogenic CO2 incidental to enhanced recovery.
(1) The monitoring, sampling, and testing plan must include the following:

(A) an analysis of the CO2 stream at a frequency sufficient to yield data representative of its chemical and physical characteristics;

(B) installation of continuous monitoring devices (including digital devices to capture periodic data) to monitor injection pressure, rate of injected CO2 , and volume of injected CO2 . The operator shall perform monitoring of daily pressure on the annulus between the tubing and the long string casing by use of either continuous monitoring device or by using a pressure gauge with a rupture disk with automated alarm to signal pressures outside of the permitted operating range. The operator may remove these devices during well workovers but must reinstall them at the completion of the workover; the Commission may approve alternative methods of monitoring the annulus between the tubing and long string casing when considering injection well construction, operating pressures, and the oil and gas reservoir;

(C) demonstration of external mechanical integrity by one of the following, or another approved, method: oxygen-activation log survey, temperature log, noise log, or casing inspection log if the operator detects a problem, or once every five years, until the well is permanently plugged;

(D) corrosion monitoring of the well materials that will come into contact with water for loss of mass, thickness, cracking, pitting, and other signs of corrosion. The operator shall perform corrosion monitoring at one or more designated representative test sites typical of the enhanced recovery facility initially and quarterly, and the operator shall report quarterly, but may be modified to a less frequent schedule as approved by the Commission, based on the construction materials, operating conditions, and monitoring history that show the well components meet minimum standards and performance by:

(i) analyzing coupons of the well construction materials placed in contact with the CO2 stream; or

(ii) routing the CO2 stream through a closed loop constructed with the material used in the well and inspecting the material in the loop; or

(iii) using an alternative method, materials, or time period approved by the Commission;

(E) annual monitoring of the injection zone pressure in the productive reservoir, including at a minimum, at least once every five years, a shut-down of each injection well for a time sufficient to estimate reservoir pressure at the site;

(F) monitoring wells as needed for continuous monitoring for pressure changes in an appropriately porous and permeable formation above the confining zone. For each well installed, the operator must set forth the specified frequency of sampling the interval and analyzing the constituents as specified in the plan;

(G) periodic monitoring of the useable quality water strata overlying the productive reservoir to monitor for changes in quality due to CO2 injection; and

(H) the use of indirect, geophysical techniques to determine the position of the CO2 fluid front, or to provide other site-specific data.

(2) For an operator to make a determination by mass balancing or actual system modeling of the quantities of anthropogenic CO2 permanently stored within the enhanced recovery reservoir for documentation to the Commission, the testing, monitoring, and reporting plan must:

(A) be based upon a site-specific assessment and may include monitoring wells or other monitoring devices to ensure that the injected anthropogenic CO2 is confined to the productive reservoir; and

(B) include a methodology for accounting for the following:

(i) the volumes of anthropogenic CO2 injected into the productive reservoir;

(ii) the anthropogenic CO2 separated from the enhanced recovery production;

(iii) the anthropogenic CO2 entrained in the production;

(iv) the volume of produced anthropogenic CO2 recycled for injection into the reservoir;

(v) any de minimis losses of anthropogenic CO2 ; and

(vi) the volume of make-up anthropogenic CO2 injected to the enhanced recovery project.

(3) Any person registering an enhanced recovery facility under this subchapter may comply with the sampling, monitoring, and reporting requirements of this subchapter by complying with, and submitting to the Commission a copy of the information submitted to the United States Environmental Protection Agency under, Subparts RR or UU of 40 CFR Part 98, Mandatory Reporting of Greenhouse Gases: Injection and Geologic Sequestration of Carbon Dioxide.

RULE §5.306 Standards for Certification

(a) The requirements of this subchapter apply in addition to the requirements of §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) and any permit conditions to which the Commission has subjected the injection wells.

(b) The operator must use a master meter or a series of master meters to meter the total volume of anthropogenic CO2 injected into the enhanced recovery facility. The operator must use an individual well meter to meter the volume of anthropogenic CO2 injected into each injection well. When anthropogenic CO2 is commingled outside the enhanced recovery facility with other CO2 , the operator shall report the total volume of anthropogenic CO2 in the mixed stream and may account for the anthropogenic CO2 for the master meter and injected well volumes on an allocated basis.

(c) The operator must install and use continuous recording devices to monitor the injection pressure and the rate, volume, and temperature of the CO2 stream. The operator must monitor the pressure on the annulus between the tubing and the long string casing. The operator must continuously record, continuously monitor, or control by a preset high-low pressure sensor switch the wellhead pressure of each injection well.

(d) The operator must fill the annulus between the tubing and the long string casing with a corrosion inhibiting fluid approved by the director.

(e) The operator of an injection well subject to this subchapter must maintain and comply with the approved monitoring, sampling, and testing plan to verify that the facility is operating as permitted and that the injected fluids are confined to the injection zone. The director may require additional monitoring as necessary to determine compliance with the intent of this subchapter.

(f) An operator registered under this subchapter must submit, as applicable, a description of any proposed well stimulation program and a determination that well stimulation will not compromise containment.

(g) In addition to the requirements of §3.14 of this title (relating to Plugging), the operator of an enhanced recovery facility subject to this subchapter must, prior to plugging:

(1) flush each injection well with a buffer fluid;

(2) measure to determine bottomhole reservoir pressure;

(3) perform final tests to assess mechanical integrity; and

(4) ensure that the material to be used in plugging is compatible with the CO2 stream and the formation fluids.

(h) In any registration for geologic storage of anthropogenic CO2 incidental to enhanced recovery, the director shall impose terms and conditions reasonably necessary to prevent the escape of CO2 .

RULE §5.307 Reporting and Recordkeeping

(a) The operator of a facility registered under this subchapter must provide, at a minimum, an annual statement, signed by an appropriate company official, confirming that the operator has complied with the requirements of this subchapter.

(b) The operator must report the results of injection pressure and injection rate monitoring of each injection well on Form H-10, Annual Disposal/Injection Well Monitoring Report, and the results of mechanical integrity testing on Form H-5, Disposal/Injection Well Pressure Test Report. Operators must submit other reports in a format acceptable to the Commission.

(c) The operator must retain all wellhead pressure records, metering records, and integrity test results for a minimum of five years.

(d) In the event the operator is unable to collect data in accordance with the approved testing, monitoring, and reporting plan, the operator shall determine the length of the specific period, such as periods of maintenance, equipment failure, or power outages, during which data were unavailable, and shall use the following procedures to estimate the data for that period.

(1) The operator shall estimate the quantity of new CO2 transferred to the enhanced recovery facility from the supplier using the quantity of new CO2 flow based upon the metering data.

(2) The operator shall estimate the quantity of CO2 metered for all CO2 , except for new CO2 transferred to the enhanced recovery facility, using the quantity of CO 2 metered under similar conditions from the nearest previous time period.

(3) The operator shall estimate the CO2 concentration values using a concentration value under similar conditions from the nearest previous time period.

(4) The operator shall estimate values for fugitive or vented CO2 emission volumes from surface equipment at the enhanced recovery facility using methods specified in Subpart W of the United States Environmental Protection Agency's Greenhouse Gas Reporting Rule, 40 Code of Federal Regulations, Part 98.

RULE §5.308 Requirements for Certification

(a) To verify geologic storage of CO 2 incidental to enhanced recovery operations, the operator must maintain, and be in compliance with, the approved testing, monitoring, and reporting plan required by §5.305 of this subchapter (relating to Monitoring, Sampling, and Testing Plan).

(b) Annually, the Commission may issue a certification to the operator validating the geologic storage of anthropogenic CO2 incidental to enhanced recovery at the registered facility.

(c) Certifications issued under this subchapter continue in effect until revoked, modified, or suspended by the Commission. The operator must comply with each requirement set forth in this subchapter as a condition of the certification unless modified by the terms of the certification.

II. The scope and management of rights
Competition with other Interests

Summary

§5.206(a)(1) and §5.206(a)(2) of the Texas CO2 Code provide that a CO2 storage facility permit may be issued if the applicant has demonstrated, among other things, that:

  1. CO2 injection and storage will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste; and
  2. with proper safeguards, underground drinking water and surface water sources can be adequately protected from CO2 migration or displaced formation fluids.  

Article/Section No.

§5.206(a)(1)
§5.206(a)(2)

Instrument Text

RULE §5.206 Permit Standards

(a) General criteria. The director may issue a permit under this subchapter if the applicant demonstrates and the director finds that:

(1) the injection and geologic storage of anthropogenic CO2 will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste as defined by Texas Natural Resources Code, §85.046(11);

(2) with proper safeguards, both underground sources of drinking water and surface water can be adequately protected from CO2 migration or displaced formation fluids;
[…]

Public participation

Summary

<p><em>Publication and notification of permit applications</em></p> <p> </p> <p>§5.204 of the Texas CO<sub>2</sub> Code requires each applicant for a storage facility permit to file a copy of the application with the County Clerk at the courthouse of each county in which the proposed facility is to be located, in order that the application can be made available for the public to inspect and copy. An electronic copy of the application must also be provided to the Texas Railroad Commission, for publication on its website.</p> <p> </p> <p>In addition, applicants must:</p> <ol> <li>publish a general notice of any application for an original or amended storage facility permit, once a week for three consecutive weeks in each newspaper of general circulation in each county where the storage facility is located or to be located; and</li> <li>notify a number of different parties who may be interested in or affected by the application, including holders of adjoining mineral interests, owners or lessees of overlying or adjoining surface lands and various administrative officials, as specified in §5.204(b)(2).</li> </ol> <p> </p> <p><em>Permit approvals and hearings</em></p> <p>If no protests against a permit application are received, the Director of the Commission’s Oil and Gas Division may administratively approve the application.</p> <p> </p> <p>If, however, a protest is received from a person notified in accordance with the requirements outlined above, the Director must:</p> <ol> <li>notify the applicant that the application cannot be administratively approved; and</li> <li>schedule a hearing on the application.</li> </ol> <p> </p> <p>Where the Director administratively denies a permit application, the applicant may also request the Director to schedule a hearing.</p> <p> </p> <p>Following any hearing, the examiner must recommend a final action to be taken by the Commission.</p>

Article/Section No.

§5.204

Instrument Text

RULE §5.204 Notice and Hearing

(a) Placement of copy of application for public inspection. The applicant must make a complete copy of the permit application available for the public to inspect and copy by filing a copy of the application with the County Clerk at the courthouse of each county where the storage facility is to be located, or if approved by the director, at another equivalent public office. The applicant also must provide an electronic copy of the complete application to enable the Commission to place the copy on the Railroad Commission Internet website. The applicant must file any subsequent revision of the application with the County Clerk or other approved public office and must file at the Commission an electronic copy of the updated application at the same time the applicant files the revision at the Commission.

(b) Notice requirements.

(1) General notice by publication. To give general notice to local governments and interested or affected persons, the applicant must publish notice of the application for an original or amended storage facility permit no later than the date the application is mailed to or filed with the director. The applicant must use the appropriate form of notice, include the information as set forth in subparagraph (A) or (B) of this paragraph, and cause the notice to be published once a week for three consecutive weeks in each newspaper of general circulation in each county where the storage facility is located or is to be located. The applicant must file proof of publication of the notice with the application.

(A) Form for notice by publication of an application for an anthropogenic CO2 geologic storage facility permit.

Attached Graphic
(B) Form for notice by publication of an application for amendment of an existing CO2 geologic storage facility permit.

Attached Graphic
(C) The applicant must submit proof of publication of notice in the following form:

Attached Graphic
(2) Individual notice.

(A) Persons to notify. By no later than the date the application is mailed to or filed with the director, the applicant must give notice of an application for a permit to operate a CO2 storage facility, or to amend an existing storage facility permit to:

(i) each adjoining mineral interest owner, other than the applicant, of the outmost boundary of the proposed geologic storage facility;

(ii) each leaseholder of minerals lying above or below the proposed storage reservoir;

(iii) each adjoining leaseholder of minerals offsetting the outermost boundary of the proposed geologic storage facility;

(iv) each owner or leaseholder of any portion of the surface overlying the proposed storage reservoir and the adjoining area of the outermost boundary of the proposed geologic storage facility;

(v) the clerk of the county or counties where the proposed storage facility is located;

(vi) the city clerk or other appropriate city official where the proposed storage facility is located within city limits; and

(vii) any other class of persons that the director determines should receive notice of the application.

(B) Content of notice. Individual notice must consist of:

(i) the applicant's intention to construct and operate an anthropogenic CO2 geologic storage facility;

(ii) a description of the geologic storage facility location;

(iii) each physical location and the internet address at which a copy of the application may be inspected; and

(iv) a statement that:

(I) affected persons may protest the application;

(II) protests must be filed in writing and must be mailed or delivered to Technical Permitting, Oil and Gas Division, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711; and

(III) protests must be received by the director within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice, whichever is later.

(3) Individual notice by publication. The applicant must make diligent efforts to ascertain the name and address of each person identified under paragraph (2)(A) of this subsection. The exercise of diligent efforts to ascertain the names and addresses of such persons requires an examination of county records where the facility is located and an investigation of any other information that is publicly and/or reasonably available to the applicant. If, after diligent efforts, an applicant has been unable to ascertain the name and address of one or more persons required to be notified under paragraph (2)(A) of this subsection, the applicant satisfies the notice requirements for those persons by the publication of the notice of application as required in paragraph (1) of this subsection. The applicant must submit an affidavit to the director specifying the efforts that the applicant took to identify each person whose name and/or address could not be ascertained.

(c) Hearing requirements.

(1) If the Commission receives a protest regarding an application for a new permit or for an amendment of an existing permit for a geologic storage facility from a person notified pursuant to subsection (b) of this section or from any other affected person within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice, whichever is later, then the director will notify the applicant that the director cannot administratively approve the application. Upon the written request of the applicant, the director will schedule a hearing on the application. The Commission must give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After the hearing, the examiner will recommend a final action by the Commission.

(2) If the Commission receives no protest regarding an application for a new permit or for the amendment of an existing permit for a geologic storage facility from a person notified pursuant to subsection (b) of this section or from any other affected person, the director may administratively approve the application.

(3) If the director administratively denies an application for a new permit or for the amendment of an existing permit for a geologic storage facility, upon the written request of the applicant, the director will schedule a hearing. After hearing, the examiner will recommend a final action by the Commission.

III. Permitting storage site exploration, project development and CO2 injection
Controls on site selection

Summary

§5.206(a) of the Texas CO2 Code provides that a CO2 storage facility permit may be issued if the applicant has demonstrated, among other things, that:

  1. CO2 injection and storage will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste;
  2. with proper safeguards, underground drinking water and surface water sources can be adequately protected from CO2 migration or displaced formation fluids;
  3. CO2 injection will not endanger or injure human health and safety;
  4. the reservoir into which CO2 is to be injected is suitable for, or capable of being made suitable for, protecting against the escape or migration of CO2 from the storage reservoir; and
  5. the facility will be sited in an area with suitable geology. 

Article/Section No.

§5.206(a)

Instrument Text

RULE §5.206 Permit Standards

(a) General criteria. The director may issue a permit under this subchapter if the applicant demonstrates and the director finds that:

(1) the injection and geologic storage of anthropogenic CO2 will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste as defined by Texas Natural Resources Code, §85.046(11);

(2) with proper safeguards, both underground sources of drinking water and surface water can be adequately protected from CO2 migration or displaced formation fluids;

(3) the injection of anthropogenic CO2 will not endanger or injure human health and safety;

(4) the reservoir into which the anthropogenic CO2 is injected is suitable for or capable of being made suitable for protecting against the escape or migration of anthropogenic CO2 from the storage reservoir;

(5) the geologic storage facility will be sited in an area with suitable geology, which at a minimum must include:

(A) an injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the CO2 stream; and

(B) a confining zone(s) that is laterally continuous and free of known transecting transmissive faults or fractures over an area sufficient to contain the injected CO2 stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without compromising the confining zone or causing the movement of fluids that endangers underground sources of drinking water;

(6) the applicant for the permit meets all of the other statutory and regulatory requirements for the issuance of the permit;

(7) the applicant has provided a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with §5.203(o) of this title (relating to Application Requirements);
[…]

Environmental protection and impact assessment

Summary

§5.206(a) of the Texas CO2 Code provides that a CO2 storage facility permit may be issued if the applicant has demonstrated, among other things, that:

  1. with proper safeguards, underground drinking water and surface water sources can be adequately protected from CO2 migration or displaced formation fluids;
  2. CO2 injection will not endanger or injure human health and safety; and
  3. the reservoir into which CO2 is to be injected is suitable for, or capable of being made suitable for, protecting against the escape or migration of CO2 from the storage reservoir.

 

§5.202(d) provides that, subject to providing notice and an opportunity for a hearing, the Director of the Oil and Gas Division of the Texas Railroad Commission may modify, suspend, or cancel a geologic storage facility permit if, among other things:

  1. underground sources of drinking water are likely to be endangered as a result of the continued operation of the facility; or
  2. fluids are escaping or are likely to escape from the injection zone.

 

If there is an emergency that endangers underground sources of drinking water or life or property or threatens the uncontrolled release of CO2, the Director may immediately order suspension of the operation of the facility until a final order is issued pursuant to a hearing.

Article/Section No.

§5.202(d)
§5.206(a)

Instrument Text

RULE §5.202 Permit Required

[…]
(d) Modification, cancellation, or suspension of a geologic storage facility permit.

(1) General. The director may modify, suspend, or cancel a geologic storage facility permit after notice and opportunity for hearing under any of the following circumstances:

(A) There is a material change in conditions in the operation of the geologic storage facility, or there are material deviations from the information originally furnished to the director. A change in conditions at a facility that does not affect the ability of the facility to operate without causing an unauthorized release of CO2 and/or formation fluids is not considered to be material;

(B) Underground sources of drinking water are likely to be endangered as a result of the continued operation of the geologic storage facility;

(C) There are substantial violations of the terms and provisions of the permit or of applicable Commission orders or regulations;

(D) The operator misrepresented material facts during the permit application or issuance process; or

(E) Fluids are escaping or are likely to escape from the injection zone.

(2) Emergency shutdown. Notwithstanding the provisions of paragraph (1) of this subsection, in the event of an emergency that threatens endangerment to underground sources of drinking water or to life or property, or an imminent threat of uncontrolled release of CO2 , the director may immediately order suspension of the operation of the geologic storage facility until a final order is issued pursuant to a hearing, if any.
[…]
RULE §5.206 Permit Standards

(a) General criteria. The director may issue a permit under this subchapter if the applicant demonstrates and the director finds that:

(1) the injection and geologic storage of anthropogenic CO2 will not endanger or injure any existing or prospective oil, gas, geothermal, or other mineral resource, or cause waste as defined by Texas Natural Resources Code, §85.046(11);

(2) with proper safeguards, both underground sources of drinking water and surface water can be adequately protected from CO2 migration or displaced formation fluids;

(3) the injection of anthropogenic CO2 will not endanger or injure human health and safety;

(4) the reservoir into which the anthropogenic CO2 is injected is suitable for or capable of being made suitable for protecting against the escape or migration of anthropogenic CO2 from the storage reservoir;

(5) the geologic storage facility will be sited in an area with suitable geology, which at a minimum must include:

(A) an injection zone of sufficient areal extent, thickness, porosity, and permeability to receive the total anticipated volume of the CO2 stream; and

(B) a confining zone(s) that is laterally continuous and free of known transecting transmissive faults or fractures over an area sufficient to contain the injected CO2 stream and displaced formation fluids and allow injection at proposed maximum pressures and volumes without compromising the confining zone or causing the movement of fluids that endangers underground sources of drinking water;

(6) the applicant for the permit meets all of the other statutory and regulatory requirements for the issuance of the permit;

(7) the applicant has provided a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with §5.203(o) of this title (relating to Application Requirements);
[…]

Permitting CO2 injection and storage

Summary

Obligation to obtain a permit
§5.202 of the Texas CO2 Code stipulates that persons may not begin drilling or operating a CO2 injection well for storage purposes, or constructing or operating a CO2 storage facility, without first obtaining the necessary permits from the Texas Railroad Commission.

Contents of permit applications
§5.203 requires that permit applications include, among other things:
1. surface maps, including proposed injection wells and boundaries;
2. geologic, geochemical and hydrologic information;
3. information regarding the projected migration of the CO2 plume, existing wells and mines that require corrective action to avoid danger to underground drinking water resources, and a corrective action plan;
4. criteria for the construction of injection wells, including with regard to suitability and casing;
5. well construction information and well construction and stimulation plans;
6. a mechanical integrity testing plan and related information;
7. an operating plan, including injection rate and pressure information and CO2 sources, volumes and characteristics;
8. a monitoring, sampling and testing plan (monitoring results must be reported annually);
9. a well plugging plan;
10. an emergency and remedial response plan; and
11. a post-injection storage facility care and closure plan.

Publication and notification of permit applications
Under §5.203, applications for permits must be filed with the Commission’s Oil and Gas Division, and copies provided to the appropriate district office(s) and the Executive Director of the Texas Commission on Environmental Quality.

§5.204 of the Code further requires each applicant for a storage facility permit to file a copy of the application with the county clerk at the courthouse of each county in which the proposed facility is to be located, in order that it can be made available for the public to inspect and copy. An electronic copy of the application must also be provided to the Texas Railroad Commission, for publication on its website.

In addition, applicants must:
1. publish a general notice of the application for an original or amended storage facility permit, once a week for three consecutive weeks in each newspaper of general circulation in each county where the storage facility is located or is to be located; and
2. notify a number of different parties who may be interested in or affected by the application, including holders of adjoining mineral interests, owners or lessees of overlying or adjoining surface lands and various administrative officials, as specified in §5.204(b)(2).

Permit approvals and hearings
If no protests against a permit application are received, under §5.204(c) the Director of the Oil and Gas Division may administratively approve the application.

If, however, a protest is received from a person notified in accordance with the requirements outlined above, the Director must:
1. notify the applicant that the application cannot be administratively approved; and
2. schedule a hearing on the application.

Where the Director administratively denies a permit application, the applicant may also request the Director to schedule a hearing.

Following any hearing, the examiner must recommend a final action to be taken by the Commission.

Fees
Permit applicants and operators of CO2 storage facilities are required under §5.205(a) to pay a range of fees, including:
1. a fee of $50 000 for each new permit application;
2. a fee of $25 000 for any application to amend an existing permit;
3. an injection fee of $0.025 per metric ton of CO2 injected; and
4. an annual post-injection care fee of $50 000, payable each year the operator does not inject CO2 at the facility, until the director has authorised storage facility closure.

Modification, suspension and cancellation of permits
Under §5.202(d), the Director of the Commission’s Oil and Gas Division may modify, suspend, or cancel a permit if:
1. there is a material change in conditions in the operation of the geologic storage facility, or material deviations from the information originally provided;
2. underground sources of drinking water are likely to be endangered as a result of the continued operation of the facility;
3. there are substantial violations of the permit or of applicable Commission orders or regulations;
4. the operator misrepresented material facts during the permit application or issuance process; or
5. fluids are escaping or are likely to escape from the injection zone.

Article/Section No.

§5.202
§5.203
§5.204

Instrument Text

RULE §5.202 Permit Required

(a) Permit required. A person may not begin drilling or operating an anthropogenic CO2 injection well for geologic storage or constructing or operating a geologic storage facility regulated under this subchapter without first obtaining the necessary permit(s) from the Commission.

(b) Permit amendment.

(1) An operator must file an application to amend an existing geologic storage facility permit with the director:

(A) prior to expanding the areal extent of the storage reservoir;

(B) prior to increasing the permitted injection pressure;

(C) prior to adding injection wells; or

(D) at any time that conditions at the geologic storage facility materially deviate from the conditions specified in the permit or permit application.

(2) Compliance with plan amendments required by this subchapter does not necessarily constitute a material deviation in conditions requiring an amendment of the permit.

(c) Permit transfer. An operator may transfer its geologic storage facility permit to another operator if the requirements of this subsection are met. A new operator may not assume operation of the geologic storage facility without a valid permit.

(1) Notice. An applicant must submit written notice of an intended permit transfer to the director at least 45 days prior to the date the transfer of operations is proposed to take place, unless such action could trigger U. S. Securities and Exchange Commission fiduciary and insider trading restrictions and/or rules.

(A) The applicant's notice to the director must contain:

(i) the name and address of the person to whom the geologic storage facility will be sold, assigned, transferred, leased, conveyed, exchanged, or otherwise disposed;

(ii) the name and location of the geologic storage facility and a legal description of the land upon which the storage facility is situated;

(iii) the date that the sale, assignment, transfer, lease conveyance, exchange, or other disposition is proposed to become final; and

(iv) the date that the transferring operator will relinquish possession as a result of the sale, assignment, transfer, lease conveyance, exchange, or other disposition.

(B) The person acquiring a geologic storage facility, whether by purchase, transfer, assignment, lease, conveyance, exchange, or other disposition, must notify the director in writing of the acquisition as soon as it is reasonably possible but not later than five business days after the date that the acquisition of the geologic storage facility becomes final. The director may not approve the transfer of a geologic storage facility permit until the new operator provides all of the following:

(i) the name and address of the operator from which the geologic storage facility was acquired;

(ii) the name and location of the geologic storage facility and a description of the land upon which the geologic storage facility is situated;

(iii) the date that the acquisition became or will become final;

(iv) the date that possession was or will be acquired; and

(v) the financial assurance required by this subchapter.

(2) Evidence of financial responsibility. The operator acquiring the permit must provide the director with evidence of financial responsibility satisfactory to the director in accordance with §5.205 of this title (relating to Fees, Financial Responsibility, and Financial Assurance).

(3) Transfer of responsibility. An operator remains responsible for the geologic storage facility until the director approves in writing the sale, assignment, transfer, lease, conveyance, exchange, or other disposition and the person acquiring the storage facility complies with all applicable requirements.

(d) Modification, cancellation, or suspension of a geologic storage facility permit.

(1) General. The director may modify, suspend, or cancel a geologic storage facility permit after notice and opportunity for hearing under any of the following circumstances:

(A) There is a material change in conditions in the operation of the geologic storage facility, or there are material deviations from the information originally furnished to the director. A change in conditions at a facility that does not affect the ability of the facility to operate without causing an unauthorized release of CO2 and/or formation fluids is not considered to be material;

(B) Underground sources of drinking water are likely to be endangered as a result of the continued operation of the geologic storage facility;

(C) There are substantial violations of the terms and provisions of the permit or of applicable Commission orders or regulations;

(D) The operator misrepresented material facts during the permit application or issuance process; or

(E) Fluids are escaping or are likely to escape from the injection zone.

(2) Emergency shutdown. Notwithstanding the provisions of paragraph (1) of this subsection, in the event of an emergency that threatens endangerment to underground sources of drinking water or to life or property, or an imminent threat of uncontrolled release of CO2 , the director may immediately order suspension of the operation of the geologic storage facility until a final order is issued pursuant to a hearing, if any.

RULE §5.203 Application Requirements


(a) General.

(1) Form and filing. Each applicant for a permit to construct and operate a geologic storage facility must file an application with the division in Austin on a form prescribed by the Commission. The applicant must file one copy of the application and all attachments with the division in an electronic format. On the same date, the applicant must file one copy with the appropriate district office(s) and one copy with the Executive Director of the Texas Commission on Environmental Quality. An applicant must ensure that the application is executed by a party having knowledge of the facts entered on the form and included in the required attachments. If otherwise required under Occupations Code, Chapter 1001, relating to Texas Engineering Practices Act, or Chapter 1002, relating to Texas Geoscientists Practices Act, respectively, a licensed professional engineer or geoscientist must conduct the geologic and hydrologic evaluations required under this section and must affix the appropriate seal on the resulting reports of such evaluations.

(2) General information. On the application, the applicant must include the name, mailing address, and location of the facility for which the application is being submitted and the operator's name, address, telephone number, Commission Organization Report number, and ownership of the facility.

(3) Application completeness. The Commission may not issue a permit before receiving a complete application. A permit application is complete when the director determines that the application contains information addressing each application requirement of the regulatory program and all information necessary to initiate the final review by the director.

(4) Reports. An applicant must ensure that all descriptive reports are prepared by a qualified and knowledgeable person and include an interpretation of the results of all logs, surveys, sampling, and tests required in this subchapter. The applicant must include in the application a quality assurance and surveillance plan for all testing and monitoring, which includes, at a minimum, validation of the analytical laboratory data, calibration of field instruments, and an explanation of the sampling and data acquisition techniques.

(b) Surface map and information. Only information of public record is required to be included on this map.

(1) The applicant must file with the director a surface map delineating the proposed location(s) of injection well(s) and the boundary of the geologic storage facility for which a permit is sought and the applicable area of review.

(2) The applicant must show within the area of review on the map the number or name and the location of:

(A) all known artificial penetrations through the confining zone, including injection wells, producing wells, inactive wells, plugged wells, or dry holes;

(B) the locations of cathodic protection holes, subsurface cleanup sites, bodies of surface water, springs, surface and subsurface mines, quarries, and water wells; and

(C) other pertinent surface features, including pipelines, roads, and structures intended for human occupancy.

(3) The applicant must identify on the map any known or suspected faults expressed at the surface.

(c) Geologic, geochemical, and hydrologic information.

(1) The applicant must submit a descriptive report prepared by a knowledgeable person that includes an interpretation of the results of appropriate logs, surveys, sampling, and testing sufficient to determine the depth, thickness, porosity, permeability, and lithology of, and the geochemistry of any formation fluids in, all relevant geologic formations.

(2) The applicant must submit information on the geologic structure and reservoir properties of the proposed storage reservoir and overlying formations, including the following information:

(A) geologic and topographic maps and cross sections illustrating regional geology, hydrogeology, and the geologic structure of the area from the ground surface to the base of the injection zone within the area of review that indicate the general vertical and lateral limits of all underground sources of drinking water within the area of review, their positions relative to the storage reservoir and the direction of water movement, where known;

(B) the depth, areal extent, thickness, mineralogy, porosity, permeability, and capillary pressure of, and the geochemistry of any formation fluids in, the storage reservoir and confining zone and any other relevant geologic formations, including geology/facies changes based on field data, which may include geologic cores, outcrop data, seismic surveys, well logs, and lithologic descriptions, and the analyses of logging, sampling, and testing results used to make such determinations;

(C) the location, orientation, and properties of known or suspected transmissive faults or fractures that may transect the confining zone within the area of review and a determination that such faults or fractures would not compromise containment;

(D) the seismic history, including the presence and depth of seismic sources, and a determination that the seismicity would not compromise containment;

(E) geomechanical information on fractures, stress, ductility, rock strength, and in situ fluid pressures within the confining zone;

(F) a description of the formation testing program used and the analytical results used to determine the chemical and physical characteristics of the injection zone and the confining zone; and

(G) baseline geochemical data for subsurface formations that will be used for monitoring purposes, including all formations containing underground sources of drinking water within the area of review.

(d) Area of review and corrective action. This subsection describes the standards for the information regarding the delineation of the area of review, the identification of penetrations, and corrective action that an applicant must include in an application.

(1) Initial delineation of the area of review and initial corrective action. The applicant must delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells. Corrective action may be phased.

(A) Delineation of area of review.

(i) Using computational modeling that considers the volumes and the physical and chemical properties of the injected CO2 stream, the physical properties of the formation into which the CO2 stream is to be injected, and available data including data available from logging, testing, or operation of wells, the applicant must predict the lateral and vertical extent of migration for the CO2 plume and formation fluids and the pressure differentials required to cause movement of injected fluids or formation fluids into an underground source of drinking water in the subsurface for the following time periods:

(I) five years after initiation of injection;

(II) from initiation of injection to the end of the injection period proposed by the applicant; and

(III) from initiation of injection to 10 years after the end of the injection period proposed by the applicant.

(ii) The applicant must use a computational model that:

(I) is based on geologic and reservoir engineering information collected to characterize the injection zone and the confining zone;

(II) is based on anticipated operating data, including injection pressures, rates, and total volumes over the proposed duration of injection;

(III) takes into account relevant geologic heterogeneities and data quality, and their possible impact on model predictions;

(IV) considers the physical and chemical properties of injected and formation fluids; and

(V) considers potential migration through known faults, fractures, and artificial penetrations and beyond lateral spill points.

(iii) The applicant must provide the name and a description of the model, software, the assumptions used to determine the area of review, and the equations solved.

(B) Identification and table of penetrations. The applicant must identify, compile, and submit a table listing all penetrations, including active, inactive, plugged, and unplugged wells and underground mines in the area of review that may penetrate the confining zone, that are known or reasonably discoverable through specialized knowledge or experience. The applicant must provide a description of each penetration's type, construction, date drilled or excavated, location, depth, and record of plugging and/or completion or closure. Examples of specialized knowledge or experience may include reviews of federal, state, and local government records, interviews with past and present owners, operators, and occupants, reviews of historical information (including aerial photographs, chain of title documents, and land use records), and visual inspections of the facility and adjoining properties.

(C) Corrective action. The applicant must demonstrate whether each of the wells on the table of penetrations has or has not been plugged and whether each of the underground mines (if any) on the table of penetrations has or has not been closed in a manner that prevents the movement of injected fluids or displaced formation fluids that may endanger underground sources of drinking water or allow the injected fluids or formation fluids to escape the permitted injection zone. The applicant must perform corrective action on all wells and underground mines in the area of review that are determined to need corrective action. The operator must perform corrective action using materials suitable for use with the CO2 stream. Corrective action may be phased.

(2) Area of review and corrective action plan. As part of an application, the applicant must submit an area of review and corrective action plan that includes the following information:

(A) the method for delineating the area of review, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based;

(B) for the area of review, a description of:

(i) the minimum frequency subject to the annual certification pursuant to §5.206(f) of this title (relating to Permit Standards) at which the applicant proposes to re-evaluate the area of review during the life of the geologic storage facility;

(ii) how monitoring and operational data will be used to re-evaluate the area of review; and

(iii) the monitoring and operational conditions that would warrant a re-evaluation of the area of review prior to the next scheduled re-evaluation; and

(C) a corrective action plan that describes:

(i) how the corrective action will be conducted;

(ii) how corrective action will be adjusted if there are changes in the area of review;

(iii) if a phased corrective action is planned, how the phasing will be determined; and

(iv) how site access will be secured for future corrective action.

(e) Injection well construction.

(1) Criteria for construction of anthropogenic CO2 injection wells. This paragraph establishes the criteria for the information about the construction and casing and cementing of, and special equipment for, anthropogenic CO2 injection wells that an applicant must include in an application.

(A) General. The operator of a geologic storage facility must ensure that all anthropogenic CO2 injection wells are constructed and completed in a manner that will:

(i) prevent the movement of injected CO2 or displaced formation fluids into any unauthorized zones or into any areas where they could endanger underground sources of drinking water;

(ii) allow the use of appropriate testing devices and workover tools; and

(iii) allow continuous monitoring of the annulus space between the injection tubing and long string casing.

(B) Casing and cementing of anthropogenic CO2 injection wells.

(i) The operator must ensure that injection wells are cased and the casing cemented in compliance with §3.13 of this title (relating to Casing, Cementing, Drilling, and Completion Requirements).

(ii) Casing, cement, cement additives, and/or other materials used in the construction of each injection well must have sufficient structural strength and must be of sufficient quality and quantity to maintain integrity over the design life of the injection well. All well materials must be suitable for use with fluids with which the well materials may be expected to come into contact and must meet or exceed test standards developed for such materials by the American Petroleum Institute, ASTM International, or comparable standards as approved by the director.

(iii) Surface casing must extend through the base of the lowermost underground source of drinking water above the injection zone and must be cemented to the surface.

(iv) Circulation of cement may be accomplished by staging. The director may approve an alternative method of cementing in cases where the cement cannot be circulated to the surface, provided the applicant can demonstrate by using logs that the cement does not allow fluid movement between the casing and the well bore.
(v) At least one long string casing, using a sufficient number of centralizers, must extend through the injection zone. The long string casing must isolate the injection zone and other intervals as necessary for the protection of underground sources of drinking water and to ensure confinement of the injected and formation fluids to the permitted injection zone using cement and/or other isolation techniques.

(vi) The applicant must verify the integrity and location of the cement using technology capable of radial evaluation of cement quality and identification of the location of channels to ensure that underground sources of drinking water will not be endangered.

(vii) The director may exempt existing wells that have been associated with injection of CO2 for the purpose of enhanced recovery from provisions of these casing and cementing requirements if the applicant demonstrates that the well construction meets the general performance criteria in subparagraph (A) of this paragraph.

(C) Special equipment.

(i) Tubing and packer. All injection wells must inject fluids through tubing set on a mechanical packer. Packers must be set no higher than 100 feet above the top of the permitted injection interval or at a location approved by the director.

(ii) Pressure observation valve. The wellhead of each injection well must be equipped with a pressure observation valve on the tubing and each annulus of the well.

(2) Construction information. The applicant must provide the following information for each well to allow the director to determine whether the proposed well construction and completion design will meet the general performance criteria in paragraph (1) of this subsection:

(A) depth to the injection zone;

(B) hole size;

(C) size and grade of all casing and tubing strings (e.g., wall thickness, external diameter, nominal weight, length, joint specification and construction material, tubing tensile, burst, and collapse strengths);

(D) proposed injection rate (intermittent or continuous), maximum proposed surface injection pressure, and maximum proposed volume of the CO2 stream;

(E) type of packer and packer setting depth;

(F) a description of the capability of the materials to withstand corrosion when exposed to a combination of the CO2 stream and formation fluids;

(G) down-hole temperatures and pressures;

(H) lithology of injection and confining zones;

(I) type or grade of cement and additives;

(J) chemical composition and temperature of the CO2 stream; and

(K) schematic drawings of the surface and subsurface construction details.

(3) Well construction plan. The applicant must submit an injection well construction plan that meets the criteria in paragraph (1) of this subsection.

(4) Well stimulation plan. The applicant must submit, as applicable, a description of the proposed well stimulation program and a determination that well stimulation will not compromise containment.

(f) Plan for logging, sampling, and testing of injection wells after permitting but before injection. The applicant must submit a plan for logging, sampling, and testing of each injection well after permitting but prior to injection well operation. The plan need not include identical logging, sampling, and testing procedures for all wells provided there is a reasonable basis for different procedures. Such plan is not necessary for existing wells being converted to anthropogenic CO2 injection wells in accordance with this subchapter, to the extent such activities already have taken place. The plan must describe the logs, surveys, and tests to be conducted to verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, the formations that are to be used for monitoring, storage, and confinement to assure conformance with the injection well construction requirements set forth in subsection (e) of this section, and to establish accurate baseline data against which future measurements may be compared. The plan must meet the following criteria and must include the following information.
(1) Logs and surveys of newly drilled and completed injection wells.

(A) During the drilling of any hole that is constructed by drilling a pilot hole that is enlarged by reaming or another method, the operator must perform deviation checks at sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling.

(B) Before surface casing is installed, the operator must run appropriate logs, such as resistivity, spontaneous potential, and caliper logs.

(C) After each casing string is set and cemented, the operator must run logs, such as a cement bond log, variable density log, and a temperature log, to ensure proper cementing.

(D) Before long string casing is installed, the operator must run logs appropriate to the geology, such as resistivity, spontaneous potential, porosity, caliper, gamma ray, and fracture finder logs, to gather data necessary to verify the characterization of the geology and hydrology.

(2) Testing and determination of hydrogeologic characteristics of injection and confining zone.

(A) Prior to operation, the operator must conduct tests to verify hydrogeologic characteristics of the injection zone.

(B) The operator must perform an initial pressure fall-off or other test and submit to the director a written report of the results of the test, including details of the methods used to perform the test and to interpret the results, all necessary graphs, and the testing log, to verify permeability, injectivity, and initial pressure using water or CO2 .

(C) The operator must determine or calculate the fracture pressures for the injection and confining zone. If the fracture pressures are determined through calculation, the Commission will include in any permit it might issue a limit of 90% of the calculated fracture pressure to ensure that the injection pressure does not exceed the fracture pressure.

(3) Sampling.

(A) The operator must record and submit the formation fluid temperature, pH, and conductivity, the reservoir pressure, and the static fluid level of the injection zone.

(B) The operator must submit analyses of whole cores or sidewall cores representative of the injection zone and confining zone and formation fluid samples from the injection zone. The director may accept data from cores and formation fluid samples from nearby wells or other data if the operator can demonstrate to the director that such data are representative of conditions at the proposed injection well.

(g) Compatibility determination. Based on the results of the formation testing program required by subsection (f) of this section, the applicant must submit a determination of the compatibility of the CO2 stream with:

(1) the materials to be used to construct the well;

(2) fluids in the injection zone; and

(3) minerals in both the injection and the confining zone.

(h) Mechanical integrity testing.

(1) Criteria. This paragraph establishes the criteria for the mechanical integrity testing plan for anthropogenic CO2 injection wells that an applicant must include in an application.

(A) Other than during periods of well workover in which the sealed tubing-casing annulus is of necessity disassembled for maintenance or corrective procedures, the operator must maintain mechanical integrity of the injection well at all times.

(B) Before beginning injection operations and at least once every five years thereafter, the operator must demonstrate mechanical integrity for each injection well by pressure testing the tubing-casing annulus.

(C) Following an initial annulus pressure test, the operator must continuously monitor injection pressure, rate, injected volumes, and pressure on the annulus between tubing and long string casing to confirm that the injected fluids are confined to the injection zone.

(D) At least once every five years, the operator must confirm that the injected fluids are confined to the injection zone using a method approved by the director (e.g., diagnostic surveys such as oxygen-activation logging or temperature or noise logs).

(E) The operator must test injection wells after any workover that disturbs the seal between the tubing, packer, and casing in a manner that verifies mechanical integrity of the tubing and long string casing.

(F) An operator must either repair and successfully retest or plug a well that fails a mechanical integrity test.

(2) Mechanical integrity testing plan. The applicant must prepare and submit a mechanical integrity testing plan as part of a permit application. The plan must include a schedule for the performance of a series of tests at a minimum frequency of five years. The performance tests must be designed to demonstrate the internal and external mechanical integrity of each injection well. These tests may include:

(A) a pressure test with liquid or inert gas;

(B) a tracer survey such as oxygen-activation logging;

(C) a temperature or noise log;

(D) a casing inspection log; and/or

(E) any alternative method that provides equivalent or better information approved by the director.

(i) Operating information.

(1) Operating plan. The applicant must submit a plan for operating the injection wells and the geologic storage facility that complies with the criteria set forth in §5.206(c) of this title, and that outlines the steps necessary to conduct injection operations. The applicant must include the following proposed operating data in the plan:

(A) the average and maximum daily injection rates and volumes of the CO2 stream;

(B) the average and maximum surface injection pressure;

(C) the source(s) of the CO2 stream and the volume of CO2 from each source; and

(D) an analysis of the chemical and physical characteristics of the CO2 stream prior to injection.

(2) Maximum injection pressure. The director will approve a maximum injection pressure limit that:

(A) considers the risks of tensile failure and, where appropriate, geomechanical or other studies that assess the risk of tensile failure and shear failure;

(B) with a reasonable degree of certainty will avoid initiation or propagation of fractures in the confining zone or cause otherwise non-transmissive faults transecting the confining zone to become transmissive; and

(C) in no case may cause the movement of injection fluids or formation fluids in a manner that endangers underground sources of drinking water.

(j) Plan for monitoring, sampling, and testing after initiation of operation.

(1) The applicant must submit a monitoring, sampling, and testing plan for verifying that the geologic storage facility is operating as permitted and that the injected fluids are confined to the injection zone.

(2) The plan must include the following:

(A) the analysis of the CO2 stream prior to injection with sufficient frequency to yield data representative of its chemical and physical characteristics;

(B) the installation and use of continuous recording devices to monitor injection pressure, rate, and volume, and the pressure on the annulus between the tubing and the long string casing, except during workovers;

(C) after initiation of injection, the performance on a semi-annual basis of corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion to ensure that the well components meet the minimum standards for material strength and performance set forth in subsection (e)(1)(A) of this section. The operator must report the results of such monitoring annually. Corrosion monitoring may be accomplished by:

(i) analyzing coupons of the well construction materials in contact with the CO2 stream;

(ii) routing the CO2 stream through a loop constructed with the materials used in the well and inspecting the materials in the loop; or

(iii) using an alternative method, materials, or time period approved by the director;

(D) monitoring of geochemical and geophysical changes, including:

(i) periodic sampling of the fluid temperature, pH, conductivity, reservoir pressure and static fluid level of the injection zone and monitoring for pressure changes, and for changes in geochemistry, in a permeable and porous formation near to and above the top confining zone;
(ii) periodic monitoring of the quality and geochemistry of an underground source of drinking water within the area of review and the formation fluid in a permeable and porous formation near to and above the top confining zone to detect any movement of the injected CO2 through the confining zone into that monitored formation;

(iii) the location and number of monitoring wells justified on the basis of the area of review, injection rate and volume, geology, and the presence of artificial penetrations and other factors specific to the geologic storage facility; and

(iv) the monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data collected under subsection (c)(2) of this section and any modeling results in the area of review evaluation;

(E) tracking the extent of the CO2 plume and the position of the pressure front by using indirect, geophysical techniques, which may include seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools; and

(F) additional monitoring as the director may determine to be necessary to support, upgrade, and improve computational modeling of the area of review evaluation and to determine compliance with the requirements that the injection activity not allow the movement of fluid containing any contaminant into underground sources of drinking water and that the injected fluid remain within the permitted interval.

(k) Well plugging plan. The applicant must submit a well plugging plan for all injection wells and monitoring wells that penetrate the base of usable quality water that includes:

(1) a proposal for plugging all monitoring wells that penetrate the base of usable quality water and all injection wells upon abandonment in accordance with §3.14 of this title (relating to Plugging);

(2) proposals for activities to be undertaken prior to plugging an injection well, specifically:

(A) flushing each injection well with a buffer fluid;

(B) performing tests or measures to determine bottomhole reservoir pressure;

(C) performing final tests to assess mechanical integrity; and

(D) ensuring that the material to be used in plugging must be compatible with the CO2 stream and the formation fluids;

(3) a proposal for giving notice of intent to plug monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that:

(A) the operator notifies the director at least 60 days before plugging a well. At this time, if any changes have been made to the original well plugging plan, the operator must also provide a revised well plugging plan. At the discretion of the director, an operator may be allowed to proceed with well plugging on a shorter notice period; and

(B) the operator will file a notice of intention to plug and abandon (Form W-3A) a well with the appropriate Commission district office and the division in Austin at least five days prior to the beginning of plugging operations;

(4) a plugging report for monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that within 30 days after plugging the operator will file a complete well plugging record (Form W-3) in duplicate with the appropriate district office. The operator and the person who performed the plugging operation (if other than the operator) must certify the report as accurate;

(5) a plan for plugging all monitoring wells that do not penetrate the base of usable quality water in accordance with 16 TAC Chapter 76 (relating to Water Well Drillers and Water Well Pump Installers); and

(6) a plan for certifying that all monitoring wells that do not penetrate the base of usable quality water will be plugged in accordance with 16 TAC Chapter 76.

(l) Emergency and remedial response plan. The applicant must submit an emergency and remedial response plan that:

(1) accounts for the entire area of review, regardless of whether or not corrective action in the area of review is phased;

(2) describes actions to be taken to address escape from the permitted injection interval or movement of the injection fluids or formation fluids that may cause an endangerment to underground sources of drinking water during construction, operation, closure, and post-closure periods;

(3) includes a safety plan that includes emergency response procedures, provisions to provide security against unauthorized activity, and CO2 release detection and prevention measures; and

(4) includes a description of the training and testing that will be provided to each employee at the storage facility on operational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities. The operator must train all employees before commencing injection and storage operations at the facility. The operator must train each subsequently hired employee before that employee commences work at the storage facility. The operator must hold a safety meeting with each contractor prior to the commencement of any new contract work at a storage facility. Emergency measures specific to the contractor's work must be explained in the contractor safety meeting. Training schedules, training dates, and course outlines must be provided to Commission personnel upon request for the purpose of Commission review to determine compliance with this paragraph.

(m) Post-injection storage facility care and closure plan. The applicant must submit a post-injection storage facility care and closure plan. The plan must include:

(1) the pressure differential between pre-injection and predicted post-injection pressures in the injection zone;

(2) the predicted position of the CO 2 plume and associated pressure front at closure as demonstrated in the area of review evaluation required under subsection (d) of this section;

(3) a description of the proposed post-injection monitoring location, methods, and frequency;

(4) a proposed schedule for submitting post-injection storage facility care monitoring results to the division; and

(5) the estimated cost of proposed post-injection storage facility care and closure.

(n) Fees, financial responsibility, and financial assurance. The applicant must pay the fees, demonstrate that it has met the financial responsibility requirements, and provide the Commission with financial assurance as required under §5.205 of this title (relating to Fees, Financial Responsibility, and Financial Assurance).

(1) The applicant must demonstrate financial responsibility and resources for corrective action, injection well plugging, post-injection storage facility care and storage facility closure, and emergency and remedial response until the director has provided to the operator a written verification that the director has determined that the facility has reached the end of the post-injection storage facility care period.

(2) In determining whether the applicant is financially responsible, the director must rely on the following:

(A) the person's most recent audited annual report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)). The date of the audit may not be more than one year before the date of submission of the application to the division; and

(B) the person's most recent quarterly report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); or

(C) if the person is not required to file such a report, the person's most recent audited financial statement. The date of the audit must not be more than one year before the date of submission of the application to the division.

(o) Letter from the Groundwater Advisory Unit of the Oil and Gas Division. The applicant must submit a letter from the Groundwater Advisory Unit of the Oil and Gas Division in accordance with Texas Water Code, §27.046.

(p) Other information. The applicant must submit any other information requested by the director as necessary to discharge the Commission's duties under Texas Water Code, Chapter 27, Subchapter B-1, or deemed necessary by the director to clarify, explain, and support the required attachments.
RULE §5.204 Notice and Hearing

(a) Placement of copy of application for public inspection. The applicant must make a complete copy of the permit application available for the public to inspect and copy by filing a copy of the application with the County Clerk at the courthouse of each county where the storage facility is to be located, or if approved by the director, at another equivalent public office. The applicant also must provide an electronic copy of the complete application to enable the Commission to place the copy on the Railroad Commission Internet website. The applicant must file any subsequent revision of the application with the County Clerk or other approved public office and must file at the Commission an electronic copy of the updated application at the same time the applicant files the revision at the Commission.

(b) Notice requirements.

(1) General notice by publication. To give general notice to local governments and interested or affected persons, the applicant must publish notice of the application for an original or amended storage facility permit no later than the date the application is mailed to or filed with the director. The applicant must use the appropriate form of notice, include the information as set forth in subparagraph (A) or (B) of this paragraph, and cause the notice to be published once a week for three consecutive weeks in each newspaper of general circulation in each county where the storage facility is located or is to be located. The applicant must file proof of publication of the notice with the application.

(A) Form for notice by publication of an application for an anthropogenic CO2 geologic storage facility permit.

Attached Graphic
(B) Form for notice by publication of an application for amendment of an existing CO2 geologic storage facility permit.

Attached Graphic
(C) The applicant must submit proof of publication of notice in the following form:

Attached Graphic
(2) Individual notice.

(A) Persons to notify. By no later than the date the application is mailed to or filed with the director, the applicant must give notice of an application for a permit to operate a CO2 storage facility, or to amend an existing storage facility permit to:

(i) each adjoining mineral interest owner, other than the applicant, of the outmost boundary of the proposed geologic storage facility;

(ii) each leaseholder of minerals lying above or below the proposed storage reservoir;

(iii) each adjoining leaseholder of minerals offsetting the outermost boundary of the proposed geologic storage facility;

(iv) each owner or leaseholder of any portion of the surface overlying the proposed storage reservoir and the adjoining area of the outermost boundary of the proposed geologic storage facility;

(v) the clerk of the county or counties where the proposed storage facility is located;

(vi) the city clerk or other appropriate city official where the proposed storage facility is located within city limits; and

(vii) any other class of persons that the director determines should receive notice of the application.

(B) Content of notice. Individual notice must consist of:

(i) the applicant's intention to construct and operate an anthropogenic CO2 geologic storage facility;

(ii) a description of the geologic storage facility location;

(iii) each physical location and the internet address at which a copy of the application may be inspected; and

(iv) a statement that:

(I) affected persons may protest the application;

(II) protests must be filed in writing and must be mailed or delivered to Technical Permitting, Oil and Gas Division, Railroad Commission of Texas, P.O. Box 12967, Austin, Texas 78711; and

(III) protests must be received by the director within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice, whichever is later.

(3) Individual notice by publication. The applicant must make diligent efforts to ascertain the name and address of each person identified under paragraph (2)(A) of this subsection. The exercise of diligent efforts to ascertain the names and addresses of such persons requires an examination of county records where the facility is located and an investigation of any other information that is publicly and/or reasonably available to the applicant. If, after diligent efforts, an applicant has been unable to ascertain the name and address of one or more persons required to be notified under paragraph (2)(A) of this subsection, the applicant satisfies the notice requirements for those persons by the publication of the notice of application as required in paragraph (1) of this subsection. The applicant must submit an affidavit to the director specifying the efforts that the applicant took to identify each person whose name and/or address could not be ascertained.

(c) Hearing requirements.

(1) If the Commission receives a protest regarding an application for a new permit or for an amendment of an existing permit for a geologic storage facility from a person notified pursuant to subsection (b) of this section or from any other affected person within 30 days of the date of receipt of the application by the division, receipt of individual notice, or last publication of notice, whichever is later, then the director will notify the applicant that the director cannot administratively approve the application. Upon the written request of the applicant, the director will schedule a hearing on the application. The Commission must give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After the hearing, the examiner will recommend a final action by the Commission.

(2) If the Commission receives no protest regarding an application for a new permit or for the amendment of an existing permit for a geologic storage facility from a person notified pursuant to subsection (b) of this section or from any other affected person, the director may administratively approve the application.

(3) If the director administratively denies an application for a new permit or for the amendment of an existing permit for a geologic storage facility, upon the written request of the applicant, the director will schedule a hearing. After hearing, the examiner will recommend a final action by the Commission.

RULE §5.205 Fees, Financial Responsibility, and Financial Assurance


(a) Fees. In addition to the fee for each injection well required by §3.78 of this title (relating to Fees and Financial Security Requirements), the following non-refundable fees must be remitted to the Commission with the application:

(1) Base application fee.

(A) The applicant must pay to the Commission an application fee of $50,000 for each permit application for a geologic storage facility.

(B) The applicant must pay to the Commission an application fee of $25,000 for each application to amend a permit for a geologic storage facility.

(2) Injection fee. The operator must pay to the Commission an annual fee of $0.025 per metric ton of CO2 injected into the geologic storage facility.

(3) Post-injection care fee. The operator must pay to the Commission an annual fee of $50,000 each year the operator does not inject into the geologic storage facility until the director has authorized storage facility closure.

(4) The anthropogenic CO2 storage trust fund shall be capped at $5,000,000.

[…]

IV. Operating and closing storage facilities
Monitoring, reporting and verification

Summary

Under §5.203 of the Texas CO2 Code, applications for storage facility permits must include, among other things:

  1. a plan for logging, sampling and testing injection wells after permitting but before the commencement of injection; and
  2. a monitoring, sampling and testing plan for operations after injection commences.

 

Monitoring results must be reported annually (see §5.203(j)(2)(c)), and all testing and monitoring subject to quality assurance and surveillance (see §5.203(a)(4)).

 

§5.206 requires operators to:

  1. install continuous recording devices to monitor various data for the CO2 stream, wellhead, tubing and casing (see §5.206(c)(E)); and
  2. comply with the approved monitoring, sampling, and testing plan, to verify that the facility is operating as permitted and that the injected fluids are confined to the injection zone (see §5.206(d)).

 

Under §5.207, operators must provide the following reports to the Director, as well as retain the related information:

  1. test records: operators must file records of all tests with their district office, within 30 days after the testing;
  2. operating reports: operators must also file annual reports, semi-annual reports and 30-day reports, as well as 24 hour reports in the event of any significant pressure changes or other data that indicate leaks in the well or non-confinement of injected gases.

 

Finally, under §5.207(c) operators must retain all wellhead pressure records, metering records, and integrity test results for at least five years. 

Article/Section No.

§5.203(a)(4)
§5.203(f)
§5.203(j)
§5.206(c)(2)(E)
§5.206(d)
§5.207

Instrument Text

RULE §5.203 Application Requirements

(a) General.
[…]
(4) Reports. An applicant must ensure that all descriptive reports are prepared by a qualified and knowledgeable person and include an interpretation of the results of all logs, surveys, sampling, and tests required in this subchapter. The applicant must include in the application a quality assurance and surveillance plan for all testing and monitoring, which includes, at a minimum, validation of the analytical laboratory data, calibration of field instruments, and an explanation of the sampling and data acquisition techniques.
[…]
(f) Plan for logging, sampling, and testing of injection wells after permitting but before injection. The applicant must submit a plan for logging, sampling, and testing of each injection well after permitting but prior to injection well
operation. The plan need not include identical logging, sampling, and testing procedures for all wells provided there is a reasonable basis for different procedures. Such plan is not necessary for existing wells being converted to anthropogenic CO2 injection wells in accordance with this subchapter, to the extent such activities already have taken place. The plan must describe the logs, surveys, and tests to be conducted to verify the depth, thickness, porosity, permeability, and lithology of, and the salinity of any formation fluids in, the formations that are to be used for monitoring, storage, and confinement to assure conformance with the injection well construction requirements set forth in subsection (e) of this section, and to establish accurate baseline data against which future measurements may be compared. The plan must meet the following criteria and must include the following information.
(1) Logs and surveys of newly drilled and completed injection wells.

(A) During the drilling of any hole that is constructed by drilling a pilot hole that is enlarged by reaming or another method, the operator must perform deviation checks at
sufficiently frequent intervals to determine the location of the borehole and to assure that vertical avenues for fluid movement in the form of diverging holes are not created during drilling.

(B) Before surface casing is installed, the operator must run appropriate logs, such as resistivity, spontaneous potential, and caliper logs.

(C) After each casing string is set and cemented, the operator must run logs, such as a cement bond log, variable density log, and a temperature log, to ensure proper
cementing.

(D) Before long string casing is installed, the operator must run logs appropriate to the geology, such as resistivity, spontaneous potential, porosity, caliper, gamma ray, and fracture finder logs, to gather data necessary to verify the characterization of the geology and hydrology.

(2) Testing and determination of hydrogeologic characteristics of injection and confining zone.

(A) Prior to operation, the operator must conduct tests to verify hydrogeologic characteristics of the injection zone.

(B) The operator must perform an initial pressure fall-off or other test and submit to the director a written report of the results of the test, including details of the methods used to perform the test and to interpret the results, all necessary graphs, and the testing log, to verify permeability, injectivity, and initial pressure using water or CO2 .
(C) The operator must determine or calculate the fracture pressures for the injection and confining zone. If the fracture pressures are determined through calculation, the Commission will include in any permit it might issue a limit of 90% of the calculated fracture pressure to ensure that the injection pressure does not exceed the fracture pressure.
(3) Sampling.

(A) The operator must record and submit the formation fluid temperature, pH, and conductivity, the reservoir pressure, and the static fluid level of the injection zone.
(B) The operator must submit analyses of whole cores or sidewall cores representative of the injection zone and confining zone and formation fluid samples from the injection zone. The director may accept data from cores and formation fluid samples from nearby wells or other data if the operator can demonstrate to the director that such data are representative of conditions at the proposed injection well.
(j) Plan for monitoring, sampling, and testing after initiation of operation.

(1) The applicant must submit a monitoring, sampling, and testing plan for verifying that the geologic storage facility is operating as permitted and that the injected fluids are confined to the injection zone.

(2) The plan must include the following:

(A) the analysis of the CO2 stream prior to injection with sufficient frequency to yield data representative of its chemical and physical characteristics;

(B) the installation and use of continuous recording devices to monitor injection pressure, rate, and volume, and the pressure on the annulus between the tubing and the long string casing, except during workovers;

(C) after initiation of injection, the performance on a semi-annual basis of corrosion monitoring of the well materials for loss of mass, thickness, cracking, pitting, and other signs of corrosion to ensure that the well components meet the
minimum standards for material strength and performance set forth in subsection (e)(1)(A) of this section. The operator must report the results of such monitoring annually. Corrosion monitoring may be accomplished by:

(i) analyzing coupons of the well construction materials in contact with the CO2 stream;

(ii) routing the CO2 stream through a loop constructed with the materials used in the well and inspecting the materials in the loop; or

(iii) using an alternative method, materials, or time period approved by the director;

(D) monitoring of geochemical and geophysical changes, including:

(i) periodic sampling of the fluid temperature, pH, conductivity, reservoir pressure and static fluid level of the injection zone and monitoring for pressure changes, and for changes in geochemistry, in a permeable and porous formation near to and above the top confining zone;
(ii) periodic monitoring of the quality and geochemistry of an underground source of drinking water within the area of review and the formation fluid in a permeable and porous formation near to and above the top confining zone to detect
any movement of the injected CO2 through the confining zone into that monitored formation;

(iii) the location and number of monitoring wells justified on the basis of the area of review, injection rate and volume, geology, and the presence of artificial penetrations and other factors specific to the geologic storage facility; and
(iv) the monitoring frequency and spatial distribution of monitoring wells based on baseline geochemical data collected under subsection (c)(2) of this section and any modeling results in the area of review evaluation;

(E) tracking the extent of the CO2 plume and the position of the pressure front by using indirect, geophysical techniques, which may include seismic, electrical, gravity, or electromagnetic surveys and/or down-hole CO2 detection tools; and

(F) additional monitoring as the director may determine to be necessary to support, upgrade, and improve computational modeling of the area of review evaluation and to determine compliance with the requirements that the injection activity not allow the movement of fluid containing any contaminant into underground sources of drinking water and that the injected fluid remain within the permitted interval.
[…]
RULE §5.206 Permit Standards

(c) Operating a geologic storage facility.
[…]
(2) Operating criteria.
[…]
(E) The operator must install and use continuous recording devices to monitor the injection pressure, and the rate, volume, and temperature of the CO2 stream. The operator must monitor the pressure on the annulus between the tubing and the long string casing. The operator must continuously record, continuously monitor, or control by a preset high-low pressure sensor switch the wellhead pressure of each injection well.
[…]
(d) Monitoring, sampling, and testing requirements. The operator of an anthropogenic CO2 injection well must maintain and comply with the approved monitoring, sampling, and testing plan to verify that the geologic storage facility is operating as permitted and that the injected fluids are confined to the injection zone. The director may require additional monitoring as necessary to support, upgrade, and improve computational modeling of the area of review evaluation and to determine compliance with the requirement that the injection activity not allow movement of fluid that would endanger underground sources of drinking water.
[…]
RULE §5.207 Reporting and Record-Keeping

(a) The operator of a geologic storage facility must provide, at a minimum, the following reports to the director and retain the following information.

(1) Test records. The operator must file a complete record of all tests in duplicate with the district office within 30 days after the testing. In conducting and evaluating the tests enumerated in this subchapter or others to be allowed by the director, the operator and the director must apply methods and standards generally accepted in the industry. When the operator reports the results of mechanical integrity tests to the director, the operator must include a description of the test(s) and the method(s) used. In making this evaluation, the director must review monitoring and other test data submitted since the previous evaluation.

(2) Operating reports. The operator also must include summary cumulative tables of the information required by the reports listed in this paragraph.

(A) Report within 24 hours. The operator must report to the appropriate district office the discovery of any significant pressure changes or other monitoring data that indicate the presence of leaks in the well or the lack of confinement of the injected gases to the geologic storage reservoir. Such report must be made orally as soon as practicable, but within 24 hours, following the discovery of the leak, and must be confirmed in writing within five working days.

(B) Report within 30 days. The operator must report:

(i) the results of periodic tests for mechanical integrity;

(ii) the results of any other test of the injection well conducted by the operator if required by the director; and

(iii) a description of any well workover.

(C) Semi-annual report. The operator must report:

(i) a summary of well head pressure monitoring;

(ii) changes to the physical, chemical, and other relevant characteristics of the CO2 stream from the proposed operating data;

(iii) monthly average, maximum and minimum values for injection pressure, flow rate and volume, and annular pressure;

(iv) a description of any event that significantly exceeds operating parameters for annulus pressure or injection pressure as specified in the permit;

(v) a description of any event that triggers a shutdown device and the response taken; and

(vi) the results of monitoring prescribed under §5.206(d) of this title (relating to Permit Standards).

(D) Annual reports. The operator must submit an annual report detailing:

(i) corrective action performed;

(ii) new wells installed and the type, location, number, and information required in §5.203(e) of this title (relating to Application Requirements);

(iii) re-calculated area of review unless the operator submits a statement signed by an appropriate company official confirming that monitoring and operational data supports the current delineation of the area of review on file with the Commission;

(iv) the updated area for which the operator has a good faith claim to the necessary and sufficient property rights to operate the geologic storage facility;

(v) tons of CO2 injected; and

(vi) The operator must maintain and update required plans in accordance with the provisions of this subchapter.

(I) Operators must submit an annual statement, signed by an appropriate company official, confirming that the operator has:

(-a-) reviewed the monitoring and operational data that are relevant to a decision on whether to reevaluate the area of review and the monitoring and operational data that are relevant to a decision on whether to update an approved plan required by §5.203 or §5.206 of this title; and

(-b-) determined whether any updates were warranted by material change in the monitoring and operational data or in the evaluation of the monitoring and operational data by the operator.

(II) Operators must submit either the updated plan or a summary of the modifications for each plan for which an update the operator determined to be warranted pursuant to subclause (I) of this clause. The director may require submission of copies of any updated plans and/or additional information regarding whether or not updates of any particular plans are warranted.

(III) The director may require the revision of any required plan whenever the director determines that such a revision is necessary to comply with the requirements of this title.

(vii) other information as required by the permit.

(b) Report format. The operator must report the results of injection pressure and injection rate monitoring of each injection well on Form H-10, Annual Disposal/Injection Well Monitoring Report, and the results of mechanical integrity testing on Form H-5, Disposal/Injection Well Pressure Test Report. Operators must submit other reports in a format acceptable to the Commission. At the discretion of the director, other formats may be accepted.

(c) Record retention. The operator must retain all wellhead pressure records, metering records, and integrity test results for at least five years. The operator must retain all documentation of good faith claim to necessary and sufficient property rights to operate the geologic storage facility until the director issues the final certificate of closure in accordance with §5.206(j)(7) of this title.

Corrective and remedial measures

Summary

Under §5.203 of the Texas CO2 Code, applications for CO2 storage facility permits must include, among other things:
1. information regarding the projected migration of the CO2 plume, existing wells and mines that require corrective action to avoid danger to underground drinking water resources, and a corrective action plan; and
2. an emergency and remedial response plan.

§5.206(f) requires operators of CO2 storage facilities, whenever warranted by a material change in monitoring data or the evaluation of that data, to:
1. re-evaluate the area of review and identify all wells in the re-evaluated area that require corrective action;
2. perform corrective action on the wells requiring corrective action; and
3. submit an amended area of review and corrective action plan, or demonstrate that no change to the area of review and corrective action plan is needed.

Operators are required under §5.206(g) to comply with the approved emergency and remedial response plan required by §5.203(l), and undertake occupational safety and emergency response training for employees.

If there is evidence that injected CO2 may endanger underground sources of drinking water, under §5.206(g)(3) the operator must:
1. immediately cease injection;
2. take all steps reasonably necessary to identify and characterise any CO2 release;
3. notify the Director of the Oil and Gas Division of the Texas Railroad Commission as soon as practicable, and within at least twenty four hours; and
4. implement the approved emergency and remedial response plan.

The Director may allow resumption of injection prior to remediation if the operator demonstrates that injection will not endanger underground drinking water sources.

Article/Section No.

§5.203(d)
§5.203(l)
§5.206(f)
§5.206(g)

Instrument Text

RULE §5.203 Application Requirements

[…]
(d) Area of review and corrective action. This subsection describes the standards for the information regarding the delineation of the area of review, the identification of penetrations, and corrective action that an applicant must include in an application.

(1) Initial delineation of the area of review and initial corrective action. The applicant must delineate the area of review, identify all wells that require corrective action, and perform corrective action on those wells. Corrective action may be phased.

(A) Delineation of area of review.

(i) Using computational modeling that considers the volumes and the physical and chemical properties of the injected CO2 stream, the physical properties of the formation into which the CO2 stream is to be injected, and available data including data available from logging, testing, or operation of wells, the applicant must predict the lateral and vertical extent of migration for the CO2 plume and formation fluids and the pressure differentials required to cause movement of injected fluids or formation fluids into an underground source of drinking water in the subsurface for the following time periods:
(I) five years after initiation of injection;

(II) from initiation of injection to the end of the injection period proposed by the applicant; and

(III) from initiation of injection to 10 years after the end of the injection period proposed by the applicant.

(ii) The applicant must use a computational model that:

(I) is based on geologic and reservoir engineering information collected to characterize the injection zone and the confining zone;

(II) is based on anticipated operating data, including injection pressures, rates, and total volumes over the proposed duration of injection;

(III) takes into account relevant geologic heterogeneities and data quality, and their possible impact on model predictions;

(IV) considers the physical and chemical properties of injected and formation fluids; and

(V) considers potential migration through known faults, fractures, and artificial penetrations and beyond lateral spill points.
(iii) The applicant must provide the name and a description of the model, software, the assumptions used to determine the area of review, and the equations solved.

(B) Identification and table of penetrations. The applicant must identify, compile, and submit a table listing all penetrations, including active, inactive, plugged, and
unplugged wells and underground mines in the area of review that may penetrate the confining zone, that are known or reasonably discoverable through specialized knowledge or experience. The applicant must provide a description of each penetration's type, construction, date drilled or excavated, location, depth, and record of plugging and/or completion or closure. Examples of specialized knowledge or experience may include reviews of federal, state, and local government records, interviews with past and present owners, operators, and occupants, reviews of historical information (including aerial photographs, chain of title documents, and land use records), and visual inspections of the facility and adjoining properties.

(C) Corrective action. The applicant must demonstrate whether each of the wells on the table of penetrations has or has not been plugged and whether each of the underground mines (if any) on the table of penetrations has or has not been closed in a manner that prevents the movement of injected fluids or displaced formation fluids that may endanger underground sources of drinking water or allow the injected fluids or formation fluids to escape the permitted injection zone. The applicant must perform corrective action on all wells and underground mines in the area of review that are determined to need corrective action. The operator must perform corrective action using materials suitable for use with the CO2 stream. Corrective action may be phased.
(2) Area of review and corrective action plan. As part of an application, the applicant must submit an area of review and corrective action plan that includes the following information:

(A) the method for delineating the area of review, including the model to be used, assumptions that will be made, and the site characterization data on which the model will be based;

(B) for the area of review, a description of:

(i) the minimum frequency subject to the annual certification pursuant to §5.206(f) of this title (relating to Permit Standards) at which the applicant proposes to re-evaluate the area of review during the life of the geologic storage facility;

(ii) how monitoring and operational data will be used to re-evaluate the area of review; and

(iii) the monitoring and operational conditions that would warrant a re-evaluation of the area of review prior to the next scheduled re-evaluation; and

(C) a corrective action plan that describes:

(i) how the corrective action will be conducted;

(ii) how corrective action will be adjusted if there are changes in the area of review;

(iii) if a phased corrective action is planned, how the phasing will be determined; and

(iv) how site access will be secured for future corrective action.
[…]
(l) Emergency and remedial response plan. The applicant must submit an emergency and remedial response plan that:

(1) accounts for the entire area of review, regardless of whether or not corrective action in the area of review is phased;

(2) describes actions to be taken to address escape from the permitted injection interval or movement of the injection fluids or formation fluids that may cause an endangerment to underground sources of drinking water during construction, operation, closure, and post-closure periods;

(3) includes a safety plan that includes emergency response procedures, provisions to provide security against unauthorized activity, and CO2 release detection and prevention measures; and

(4) includes a description of the training and testing that will be provided to each employee at the storage facility on operational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities. The operator must train all employees before commencing injection and storage operations at the facility. The operator must train each subsequently hired employee
before that employee commences work at the storage facility. The operator must hold a safety meeting with each contractor prior to the commencement of any new contract work at a storage facility. Emergency measures specific to the contractor's work must be explained in the contractor safety meeting. Training schedules, training dates, and course outlines must be provided to Commission personnel upon request for the purpose of Commission review to determine compliance with this paragraph.
[…]
RULE §5.206 Permit Standards
[…]
(f) Area of review and corrective action. Notwithstanding the requirement in §5.203(d)(2)(B)(i) of this title to perform a re-evaluation of the area of review, at the frequency specified in the area of review and corrective action plan or permit, the operator of a geologic storage facility also must conduct the following whenever warranted by a material change in the monitoring and/or operational data or in the evaluation of the monitoring and operational data by the operator:

(1) a re-evaluation of the area of review by performing all of the actions specified in §5.203(d)(1)(A) - (C) of this title to delineate the area of review and identify all wells that require corrective action;

(2) identify all wells in the re-evaluated area of review that require corrective action;

(3) perform corrective action on wells requiring corrective action in the re-evaluated area of review in the same manner specified in §5.203(d)(1)(C) of this title; and

(4) submit an amended area of review and corrective action plan or demonstrate to the director through monitoring data and modeling results that no change to the area of review and corrective action plan is needed.

(g) Emergency, mitigation, and remedial response.

(1) Plan. The operator must maintain and comply with the approved emergency and remedial response plan required by §5.203(l) of this title. The operator must update the plan in accordance with §5.207(a)(2)(D)(vi) of this title (relating to Reporting and Record-Keeping). The operator must make copies of the plan available at the storage facility and at the company headquarters.

(2) Training.

(A) The operator must prepare and implement a plan to train and test each employee at the storage facility on occupational safety and emergency response procedures to the extent applicable to the employee's duties and responsibilities. The operator must make copies of the plan available at the geological storage facility. The operator must train all employees before commencing injection and storage operations at the facility. The operator must train each subsequently hired employee before that employee commences work at the storage facility.

(B) The operator must hold a safety meeting with each contractor prior to the commencement of any new contract work at a storage facility. The operator must explain emergency measures specific to the contractor's work in the contractor safety meeting.

(C) The operator must provide training schedules, training dates, and course outlines to Commission personnel upon request for the purpose of Commission review to determine compliance with this paragraph.

(3) Action. If an operator obtains evidence that the injected CO2 stream and associated pressure front may cause an endangerment to underground sources of drinking water, the operator must:

(A) immediately cease injection;

(B) take all steps reasonably necessary to identify and characterize any release;

(C) notify the director as soon as practicable but within at least 24 hours; and

(D) implement the approved emergency and remedial response plan.

(4) Resumption of injection. The director may allow the operator to resume injection prior to remediation if the operator demonstrates that the injection operation will not endanger underground sources of drinking water.
[…]

Financial security

Summary

Holders of CO2 storage facility permits are required under §5.205(b) of the Texas CO2 Code to provide evidence demonstrating the permit holder’s financial responsibility and resources for:

  1. corrective action;
  2. injection well plugging;
  3. post-injection storage facility care and storage facility closure; and
  4. emergency and remedial responses,

each year until the facility has reached the end of the post-injection storage facility care period.

 

§5.205(c) provides that storage facilities must not receive CO2 until the operator has obtained a bond or letter of credit for the facility in an amount equal to or greater than the maximum amount estimated to perform corrective action, emergency response, and remedial action, post-injection monitoring and site care, and closure of the geologic storage facility, and this financial security has been approved by the Director of the Oil and Gas Division of the Texas Railroad Commission.

 

Operators must also notify the Commission of, among other things, any adverse financial conditions that may affect an operator's ability to carry out injection well plugging and post-injection storage facility care and closure.

Article/Section No.

§5.205

Instrument Text

RULE §5.205 Fees, Financial Responsibility, and Financial Assurance
[…]
(b) Financial responsibility.

(1) A person to whom a permit is issued under this subchapter must provide annually to the director evidence of financial responsibility that is satisfactory to the director. The operator must demonstrate and maintain financial responsibility and resources for corrective action, injection well plugging, post-injection storage facility care and storage facility closure, and emergency and remedial response until the director has provided written verification that the director has determined that the facility has reached the end of the post-injection storage facility care period.

(2) In determining whether the person is financially responsible, the director must rely on:

(A) the person's most recent audited annual report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); and

(B) the person's most recent quarterly report filed with the U. S. Securities and Exchange Commission under Section 13 or 15(d), Securities Exchange Act of 1934 (15 U.S.C. Section 78m or 78o(d)); or

(C) if the person is not required to file such a report, the person's most recent audited financial statement. The date of the audit must not be more than one year before the date of submission of the application to the director.

(3) The applicant's demonstration of financial responsibility must account for the entire area of review, regardless of whether corrective action in the area of review is phased.

(c) Financial assurance.

(1) Injection and monitoring wells. The operator must comply with the requirements of §3.78 of this title for all monitoring wells that penetrate the base of usable quality water and all injection wells.

(2) Geologic storage facility.

(A) The applicant must include in an application for a geologic storage facility permit:

(i) a written estimate of the highest likely dollar amount necessary to perform post-injection monitoring and closure of the facility that shows all assumptions and calculations used to develop the estimate;

(ii) a copy of the form of the bond or letter of credit that will be filed with the Commission; and

(iii) information concerning the issuer of the bond or letter of credit including the issuer's name and address and evidence of authority to issue bonds or letters of credit in Texas.

(B) A geologic storage facility may not receive CO2 until a bond or letter of credit in an amount approved by the director under this subsection and meeting the requirements of this subsection as to form and issuer has been filed with and approved by the director.

(C) The determination of the amount of financial assurance for a geologic storage facility is subject to the following requirements:

(i) The director must approve the dollar amount of the financial assurance. The amount of financial assurance required to be filed under this subsection must be equal to or greater than the maximum amount necessary to perform corrective action, emergency response, and remedial action, post-injection monitoring and site care, and closure of the geologic storage facility, exclusive of plugging costs for any well or wells at the facility, at any time during the permit term in accordance with all applicable state laws, Commission rules and orders, and the permit;

(ii) A qualified professional engineer licensed by the State of Texas, as required under Occupations Code, Chapter 1001, relating to Texas Engineering Practices Act, must prepare or supervise the preparation of a written estimate of the highest likely amount necessary to close the geologic storage facility. The operator must submit to the director the written estimate under seal of a qualified licensed professional engineer, as required under Occupations Code, Chapter 1001, relating to Texas Engineering Practices Act; and

(iii) The Commission may use the proceeds of financial assurance filed under this subsection to pay the costs of plugging any well or wells at the facility if the financial assurance for plugging costs filed with the Commission is insufficient to pay for the plugging of such well or wells.

(D) Bonds and letters of credit filed in satisfaction of the financial assurance requirements for a geologic storage facility must comply with the following standards as to issuer and form.

(i) The issuer of any geologic storage facility bond filed in satisfaction of the requirements of this subsection must be a corporate surety authorized to do business in Texas. The form of bond filed under this subsection must provide that the bond be renewed and continued in effect until the conditions of the bond have been met or its release is authorized by the director.

(ii) Any letter of credit filed in satisfaction of the requirements of this subsection must be issued by and drawn on a bank authorized under state or federal law to operate in Texas. The letter of credit must be an irrevocable, standby letter of credit subject to the requirements of Texas Business and Commerce Code, §§5.101 - 5.118. The letter of credit must provide that it will be renewed and continued in effect until the conditions of the letter of credit have been met or its release is authorized by the director.

(E) The operator of a geologic storage facility must provide to the director annual written updates of the cost estimate to increase or decrease the cost estimate to account for any changes to the area of review and corrective action plan, the emergency response and remedial action plan, the injection well plugging plan, and the post-injection storage facility care and closure plan. The operator must provide to the director upon request an adjustment of the cost estimate if the director has reason to believe that the original demonstration is no longer adequate to cover the cost of injection well plugging and post-injection storage facility care and closure.

(3) The director may consider allowing the phasing in of financial assurance for only corrective action based on project-specific factors.

(4) The director may approve a reduction in the amount of financial assurance required for post-injection monitoring and/or corrective action based on project-specific monitoring results.

(d) Notice of adverse financial conditions.

(1) The operator must notify the Commission of adverse financial conditions that may affect the operator's ability to carry out injection well plugging and post-injection storage facility care and closure. An operator must file any notice of bankruptcy in accordance with §3.1(f) of this title (relating to Organization Report; Retention of Records; Notice Requirements). The operator must give such notice by certified mail.

(2) The operator filing a bond must ensure that the bond provides a mechanism for the bond or surety company to give prompt notice to the Commission and the operator of any action filed alleging insolvency or bankruptcy of the surety company or the bank or alleging any violation that would result in suspension or revocation of the surety or bank's charter or license to do business.

(3) Upon the incapacity of a bank or surety company by reason of bankruptcy, insolvency or suspension, or revocation of its charter or license, the Commission must deem the operator to be without bond coverage. The Commission must issue a notice to any operator who is without bond coverage and must specify a reasonable period to replace bond coverage, not to exceed 90 days.

Enforcement

Summary

Under §5.208 of the Texas CO2 Code, a CO2 storage facility operator who violates Subchapter B of the Code may be subject to:

  1. penalties and remedies specified in the Texas Natural Resources Code, Title 3, Texas Water Code, Chapter 27, and other statutes administered by the Texas Railroad Commission; and

revocation of their certificate of compliance for any oil, gas, or geothermal resource well. 

Article/Section No.

§5.208

Instrument Text

RULE §5.208 Penalties

(a) General. An operator that violates this subchapter may be subject to penalties and remedies specified in the Texas Natural Resources Code, Title 3, Texas Water Code, Chapter 27, and other statutes administered by the Commission.

(b) Certificate of compliance. The Commission may revoke a certificate of compliance for any oil, gas, or geothermal resource well in the manner provided in §3.73 of this title (relating to Pipeline Connection; Cancellation of Certificate of Compliance; Severance) for violation of this subchapter.

Site closure

Summary

Under §5.203 of the Texas CO2 Code, applications for storage facility permits must include, among other things:
1. a well plugging plan; and
2. a post-injection storage facility care and closure plan setting out, among other things, the predicted position of the CO2 plume and associated pressure front at closure, a description of the proposed post-injection monitoring location, methods, and frequency, and the estimated cost of proposed post-injection storage facility care and closure.

Each of these plans must be maintained and complied with in accordance with §5.206(i) and (j).

Following cessation of injection, operators are required under §5.206(j)(2) to continue monitoring until the Director of the Oil and Gas Division of the Texas Railroad Commission determines that the storage facility will not endanger underground drinking water sources and, prior to authorisation for storage facility closure, demonstrate that no additional monitoring is needed to assure that the facility will not present such danger.

In addition, operators must demonstrate:
1. the estimated magnitude and extent of the facility footprint;
2. that there is no leakage of either CO2 or displaced formation fluids that will endanger underground drinking water sources;
3. that the injected or displaced fluids are not expected to migrate in a manner that encounters a potential leakage pathway into underground drinking water sources;
4. that injection wells at the site will be plugged and abandoned in accordance with applicable requirements; and
5. that any remaining facility monitoring wells will be properly plugged or are being managed in an approved manner.

Operators must notify the Director at least 120 days before storage facility closure, and must wait until the Director has approved closure before initiating the closure process.

After closure has been approved, the operator must plug all wells in accordance with the approved well plugging plan, and submit a storage facility closure report containing:
1. documentation showing appropriate injection and monitoring well plugging;
2. documentation showing appropriate notification and information to such drilling authorities, to enable these authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zones; and
3. records reflecting the nature, composition and volume of the CO2 stream.

Upon completion of these requirements the Director must issue a certificate of closure in accordance with §5.206(j)(7), at which time the operator will be released from the requirement to maintain financial assurance under §5.205(c).

Details of the CO2 storage facility and operations must be recorded on the deed to the facility property, and records collected during the post-injection storage facility care period retained for five years following closure.

Finally, the operator must identify each location at which geologic storage activities took place, including each injection well, by a sign that includes a telephone number where the operator or a representative of the operator can be reached 24 hours a day, seven days a week in the event of an emergency.

Article/Section No.

§5.203
§5.206

Instrument Text

RULE §5.203 Application Requirements
[…]
(k) Well plugging plan. The applicant must submit a well plugging plan for all injection wells and monitoring wells that penetrate the base of usable quality water that includes:

(1) a proposal for plugging all monitoring wells that penetrate the base of usable quality water and all injection wells upon abandonment in accordance with §3.14 of this title (relating to Plugging);

(2) proposals for activities to be undertaken prior to plugging an injection well, specifically:

(A) flushing each injection well with a buffer fluid;

(B) performing tests or measures to determine bottomhole reservoir pressure;

(C) performing final tests to assess mechanical integrity; and

(D) ensuring that the material to be used in plugging must be compatible with the CO2 stream and the formation fluids;

(3) a proposal for giving notice of intent to plug monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that:

(A) the operator notifies the director at least 60 days before plugging a well. At this time, if any changes have been made to the original well plugging plan, the operator must also provide a revised well plugging plan. At the discretion of the director, an operator may be allowed to proceed with well plugging on a shorter notice period; and

(B) the operator will file a notice of intention to plug and abandon (Form W-3A) a well with the appropriate Commission district office and the division in Austin at least five days prior to the beginning of plugging operations;

(4) a plugging report for monitoring wells that penetrate the base of usable quality water and all injection wells. The applicant's plan must ensure that within 30 days after plugging the operator will file a complete well plugging record (Form W-3) in duplicate with the appropriate district office. The operator and the person who performed the plugging operation (if other than the operator) must certify the report as accurate;

(5) a plan for plugging all monitoring wells that do not penetrate the base of usable quality water in accordance with 16 TAC Chapter 76 (relating to Water Well Drillers and Water Well Pump Installers); and

(6) a plan for certifying that all monitoring wells that do not penetrate the base of usable quality water will be plugged in accordance with 16 TAC Chapter 76.
[…]
(m) Post-injection storage facility care and closure plan. The applicant must submit a post-injection storage facility care and closure plan. The plan must include:

(1) the pressure differential between pre-injection and predicted post-injection pressures in the injection zone;

(2) the predicted position of the CO 2 plume and associated pressure front at closure as demonstrated in the area of review evaluation required under subsection (d) of this section;

(3) a description of the proposed post-injection monitoring location, methods, and frequency;

(4) a proposed schedule for submitting post-injection storage facility care monitoring results to the division; and

(5) the estimated cost of proposed post-injection storage facility care and closure.
[…]
RULE §5.206 Permit Standards
[…]
(i) Well plugging. The operator of a geologic storage facility must maintain and comply with the approved well plugging plan required by §5.203(k) of this title.

(j) Post-injection storage facility care and closure.

(1) Post-injection storage facility care and closure plan.

(A) The operator of an injection well must maintain and comply with the approved post-injection storage facility care and closure plan.

(B) The operator must update the plan in accordance with §5.207(a)(2)(D)(vi) of this title.

(C) Upon cessation of injection, the operator of a geologic storage facility must either submit an amended plan or demonstrate to the director through monitoring data and modeling results that no amendment to the plan is needed.
(2) Post-injection storage facility monitoring. Following cessation of injection, the operator must continue to conduct monitoring as specified in the approved plan until the director determines that the position of the CO2 plume and pressure front are such that the geologic storage facility will not endanger underground sources of drinking water.

(3) Prior to closure. Prior to authorization for storage facility closure, the operator must demonstrate to the director, based on monitoring, other site-specific data, and modeling that is reasonably consistent with site performance that no additional monitoring is needed to assure that the geologic storage facility will not endanger underground sources of drinking water. The operator must demonstrate, based on the current understanding of the site, including monitoring data and/or modeling, all of the following:

(A) the estimated magnitude and extent of the facility footprint (the CO2 plume and the area of elevated pressure);

(B) that there is no leakage of either CO2 or displaced formation fluids that will endanger underground sources of drinking water;

(C) that the injected or displaced fluids are not expected to migrate in the future in a manner that encounters a potential leakage pathway into underground sources of drinking water;

(D) that the injection wells at the site completed into or through the injection zone or confining zone will be plugged and abandoned in accordance with these requirements; and

(E) any remaining facility monitoring wells will be properly plugged or are being managed by a person and in a manner approved by the director.

(4) Notice of intent for storage facility closure. The operator must notify the director at least 120 days before storage facility closure. At the time of such notice, if the operator has made any changes to the original plan, the operator also must provide the revised plan. The director may approve a shorter notice period.

(5) Authorization for storage facility closure. No operator may initiate storage facility closure until the director has approved closure of the storage facility in writing. After the director has authorized storage facility closure, the operator must plug all wells in accordance with the approved plan required by §5.203(k) of this title.

(6) Storage facility closure report. Once the director has authorized storage facility closure, the operator must submit a storage facility closure report within 90 days that must thereafter be retained by the Commission in Austin. The report must include the following information:

(A) documentation of appropriate injection and monitoring well plugging. The operator must provide a copy of a survey plat that has been submitted to the Regional Administrator of Region 6 of the United States Environmental Protection Agency. The plat must indicate the location of the injection well relative to permanently surveyed benchmarks;

(B) documentation of appropriate notification and information to such state and local authorities as have authority over drilling activities to enable such state and local authorities to impose appropriate conditions on subsequent drilling activities that may penetrate the injection and confining zones; and

(C) records reflecting the nature, composition and volume of the CO2 stream.

(7) Certificate of closure. Upon completion of the requirements in paragraphs (3) - (6) of this subsection, the director will issue a certificate of closure. At that time, the operator is released from the requirement in §5.205(c) of this title to maintain financial assurance.

(k) Deed notation. The operator of a geologic storage facility must record a notation on the deed to the facility property; on any other document that is normally examined during title search; or on any other document that is acceptable to the county clerk for filing in the official public records of the county that will in perpetuity provide any potential purchaser of the property the following information:

(1) a complete legal description of the affected property;

(2) that land has been used to geologically store CO2 ;

(3) that the survey plat has been filed with the Commission;

(4) the address of the office of the United States Environmental Protection Agency, Region 6, to which the operator sent a copy of the survey plat; and

(5) the volume of fluid injected, the injection zone or zones into which it was injected, and the period over which injection occurred.

(l) Retention of records. The operator must retain for five years following storage facility closure records collected during the post-injection storage facility care period. The operator must deliver the records to the director at the conclusion of the retention period, and the records must thereafter be retained at the Austin headquarters of the Commission.

(m) Signs. The operator must identify each location at which geologic storage activities take place, including each injection well, by a sign that meets the requirements specified in §3.3(1), (2), and (5) of this title (relating to Identification of Properties, Wells, and Tanks). In addition, each sign must include a telephone number where the operator or a representative of the operator can be reached 24 hours a day, seven days a week in the event of an emergency.

(n) Other permit terms and conditions. In any permit for a geologic storage facility, the director must impose terms and conditions reasonably necessary to protect underground sources of drinking water. Permits issued under this subchapter continue in effect until revoked, modified, or suspended by the Commission. The operator must comply with each requirement set forth in this subchapter as a condition of the permit unless modified by the terms of the permit.

V. Management of long-term responsibilities and liabilities
Financial contributions to long term stewardship

Summary

Operators of CO2 storage facilities are required under §5.205(a) of the Texas CO2 Code to pay, among other fees:

  1. an injection fee of $0.025 per metric ton of CO2 injected; and
  2. an annual post-injection care fee of $50 000, payable each year the operator does not inject CO2 at the facility until the director has authorized storage facility closure.

 

The amount of money held in the anthropogenic CO2 storage trust fund is capped, however, at $5 000 000.00.

Article/Section No.

§5.205(a)

Instrument Text

RULE §5.205 Fees, Financial Responsibility, and Financial Assurance

(a) Fees. In addition to the fee for each injection well required by §3.78 of this title (relating to Fees and Financial Security Requirements), the following non-refundable fees must be remitted to the Commission with the application:

(1) Base application fee.

(A) The applicant must pay to the Commission an application fee of $50,000 for each permit application for a geologic storage facility.

(B) The applicant must pay to the Commission an application fee of $25,000 for each application to amend a permit for a geologic storage facility.

(2) Injection fee. The operator must pay to the Commission an annual fee of $0.025 per metric ton of CO2 injected into the geologic storage facility.

(3) Post-injection care fee. The operator must pay to the Commission an annual fee of $50,000 each year the operator does not inject into the geologic storage facility until the director has authorized storage facility closure.

(4) The anthropogenic CO2 storage trust fund shall be capped at $5,000,000.