SECTION 3.95. Underground Storage of Liquid or Liquefied Hydrocarbons in Salt Formations

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

(1) Affected person--A person who, as a result of actions proposed in an application for a storage facility permit or for amendment or modification of an existing storage facility permit, has suffered or may suffer actual injury or economic damage other than as a member of the general public.

(2) Brine string--The uncemented tubing through which highly saline water flows into or out of a hydrocarbon storage well during hydrocarbon withdrawal or injection operations.

(3) Cavern--The storage space created in a salt formation by solution mining.

(4) Commission--The Railroad Commission of Texas.

(5) Emergency shutdown valve--A valve that automatically closes to isolate a hydrocarbon storage wellhead from surface piping in the event of specified conditions that, if uncontrolled, may cause an emergency.

(6) Fire detector--A device capable of detecting the presence of a flame or the heat from a fire.

(7) Fresh water--Water having bacteriological, physical, and chemical properties that make it suitable and feasible for beneficial use for any lawful purpose. For purposes of this section, brine associated with the creation, operation, and maintenance of an underground hydrocarbon storage facility is not considered fresh water.

(8) Hydrocarbon storage well or storage well--A well, including the storage wellhead, casing, tubing, borehole, and cavern, used for the injection or withdrawal of liquid or liquefied hydrocarbons into or out of an underground hydrocarbon storage facility.

(9) Leak detector--A device capable of detecting by chemical or physical means the presence of hydrocarbon vapor or the escape of vapor through a small opening.

(10) Liquid or liquefied hydrocarbons--Crude oil and products, derivatives, or byproducts of oil or gas that are:

(A) liquid under standard conditions of temperature and pressure;

(B) liquefied under the temperatures and pressures at which they are stored; or

(C) stored under conditions that necessitate the use of displacement fluids to withdraw them from storage.

(11) Operator--The person recognized by the Commission as being responsible for the physical operation of an underground hydrocarbon storage facility, or such person's authorized representative.

(12) Owner--The person recognized by the Commission as owning all or part of a storage facility, or such person's authorized representative.

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

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

(15) Process or transfer area--Any area at an underground hydrocarbon storage facility where hydrocarbons are physically altered by equipment, including dehydrators, compressors, and pumps, or where hydrocarbons are transferred to or from trucks, rail cars, or pipelines.

(16) Storage wellhead--Equipment installed at the surface of the wellbore, including the casinghead and tubing head, spools, block or wing valves, and instrument flanges. Spool pieces must have a length of less than six feet to be considered a part of the storage wellhead.

(17) Surface piping--Any pipe within a storage facility that is directly connected to a storage well, outboard of the wellhead emergency shutdown valve and used to transport product, brine, or fresh water to or from a storage well whether such pipe is above or below ground level.

(18) Underground hydrocarbon storage facility or storage facility--A facility used for the storage of liquid or liquefied hydrocarbons in an underground salt formation, including surface and subsurface rights, appurtenances, and improvements necessary for the operation of the facility.

(b) Permit required.

(1) General. No person may create, operate, or maintain an underground hydrocarbon storage facility without obtaining a permit from the Commission. A permit issued by the Commission for such activities before the effective date of this section shall continue in effect until revoked, modified, or suspended by the Commission, or until it expires by its terms. The provisions of this section apply to permits for underground hydrocarbon storage facility operations issued prior to the effective date of this section, except as specifically provided in this section.

(2) 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 shall control.

(c) Application.

(1) Information required. An application for a permit to create, operate, or maintain an underground hydrocarbon storage facility shall be filed with the Commission by the owner or operator, or proposed owner or operator, on the prescribed form. The application shall contain the information necessary to demonstrate compliance with the applicable state laws and Commission regulations.

(2) Permit amendment. An application for amendment of an existing underground hydrocarbon storage facility permit shall be filed with the Commission:

(A) prior to any planned enlargement of a cavern in excess of the permitted cavern capacity by solution mining;

(B) when required in accordance with paragraph (3) of this subsection;

(C) prior to the drilling of any additional hydrocarbon storage wells;

(D) prior to any increase in the volume of liquid or liquefied hydrocarbons stored in the cavern in excess of the permitted storage volume; or

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

(3) Increase in capacity. The owner or operator of a storage facility shall notify the Commission if information indicates that the capacity of a cavern exceeds the permitted cavern capacity by 20% or more. Such notification shall be made in writing to the Commission within 10 days of the date that the owner or operator knows or has reason to know that the cavern capacity exceeds the permitted capacity by 20% or more. The notification shall include a description of the information that indicates that the permitted cavern capacity has been exceeded, and an estimate of the current cavern capacity. Upon receipt of such information, the Commission or its designee may take any one or more of the following actions:

(A) require the permittee to comply with a compliance schedule that lists measures to be taken to ensure that conditions at the storage facility do not pose a danger to life or property, and that no waste of hydrocarbons, uncontrolled escape of hydrocarbons, or pollution of fresh water occurs;

(B) require the permittee to file an application to amend the underground hydrocarbon storage facility permit;

(C) modify, cancel, or suspend the permit as provided in subsection (f) of this section; or

(D) take enforcement action.

(4) Related activities. An application for a permit to store saltwater or brine in a pit or to dispose of saltwater or other oil and gas waste arising out of or incidental to the creation, operation, or maintenance of an underground hydrocarbon storage facility shall be filed in accordance with applicable Commission requirements.

(d) Standards for underground storage zone.

(1) Geologic, construction, and operating performance. An underground hydrocarbon storage facility may be created, operated, or maintained only in an impermeable salt formation in a manner that will prevent waste of the stored hydrocarbons, uncontrolled escape of hydrocarbons, pollution of fresh water, and danger to life or property. Natural gas storage operations are not authorized under the provisions of this section. A permit under §3.97 of this title (relating to Underground Storage of Gas in Salt Formations) is required to convert from storage of liquid or liquefied hydrocarbons to storage of natural gas in an underground salt formation.

(2) Fresh water strata. The applicant must submit with the application a letter from the Groundwater Advisory Unit of the Oil and Gas Division stating the depth to which fresh water strata occur at each storage facility.

(e) Notice and hearing.

(1) Notice requirements. The applicant shall, no later than the date the application is mailed to or filed with the Commission, give notice of an application for a permit to create, operate, or maintain an underground hydrocarbon storage facility, or to amend an existing storage facility permit, by mailing or delivering a copy of the application form to:

(A) the surface owner of the tract where the storage facility is located or is proposed to be located;

(B) the surface owner of each tract adjoining the tract where the storage facility is located or is proposed to be located;

(C) each oil, gas, or salt leaseholder, other than the applicant, of the tract on which the storage facility is located or is proposed to be located;

(D) each oil, gas, or salt leaseholder of any tract adjoining the tract on which the storage facility is located or is proposed to be located;

(E) the county clerk of the county where the storage facility is located or is proposed to be located; and

(F) if the storage facility is located or proposed to be located within city limits, the city clerk or other appropriate city official.

(2) Publication of notice. Notice of the application, in a form approved by the Commission or its designee, shall be published by the applicant once a week for three consecutive weeks in a newspaper of general circulation in the county or counties where the facility is or is proposed to be located. The applicant shall file proof of publication prior to any hearing on the application or administrative approval of the application.

(3) Notice by publication. The applicant shall make diligent efforts to ascertain the name and address of each person identified under paragraph (1)(A) - (D) of this subsection. The exercise of diligent efforts to ascertain the names and addresses of such persons shall require an examination of the county records where the facility is located and an investigation of any other information of which the applicant has actual knowledge. If, after diligent efforts, the applicant has been unable to ascertain the name and address of one or more persons required to be notified under paragraph (1)(A) - (D) of this subsection, the notice requirements for those persons are satisfied by the publication of the notice of application as required in paragraph (2) of this subsection. The applicant must submit an affidavit to the Commission specifying the efforts that were taken to identify each person whose name and/or address could not be ascertained.

(4) Hearing required for new permits. A permit application for a new underground hydrocarbon storage facility will be considered for approval only after notice and hearing. The Commission will give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After hearing, the examiner shall recommend a final action by the Commission.

(5) Hearing on permit amendments.

(A) An application for an amendment to an existing storage facility permit may be approved administratively if the Commission receives no protest from a person notified pursuant to the provisions of paragraph (1) of this subsection, or from any other affected person.

(B) If the Commission receives a protest from a person notified pursuant to paragraph (1) of this subsection or from any other affected person within 15 days of the date of receipt of the application by the Commission, or of the date of the third publication, whichever is later, or if the Commission determines that a hearing is in the public interest, then the applicant will be notified that the application cannot be approved administratively. The Commission will schedule a hearing on the application upon written request of the applicant. The Commission will give notice of the hearing to all affected persons, local governments, and other persons who express, in writing, an interest in the application. After hearing, the examiner shall recommend a final action by the Commission.

(C) If the application is administratively denied, a hearing will be scheduled upon written request of the applicant. After hearing, the examiner shall recommend a final action by the Commission.

(f) Modification, cancellation, or suspension of a permit.

(1) General. Any permit may be modified, suspended, or canceled after notice and opportunity for hearing if:

(A) a material change in conditions has occurred in the operation, maintenance, or construction of the storage facility, or there are material deviations from the information originally furnished to the Commission. A change in conditions at a facility that does not affect the safe operation of the facility or the ability of the facility to operate without causing waste of hydrocarbons or pollution is not considered to be material;

(B) fresh water is likely to be polluted as a result of continued operation of the facility;

(C) there are material violations of the terms and provisions of the permit or Commission regulations;

(D) the applicant has misrepresented any material facts during the permit issuance process; or

(E) injected fluids are escaping or are likely to escape from the storage facility.

(2) Imminent dangers. Notwithstanding the provisions of paragraph (1) of this subsection, in the event of an emergency that presents an imminent danger to life or property, or where waste of hydrocarbons, uncontrolled escape of hydrocarbons, or pollution of fresh water is imminent, the Commission or its designee may immediately suspend a storage facility permit until a final order is issued pursuant to a hearing, if any, conducted in accordance with the provisions of paragraph (1) of this subsection. All operations at the facility shall cease upon suspension of a permit under this paragraph.

(g) Transfer of permit. A storage facility permit may not be transferred without the prior approval of the Commission or its designee. Until such transfer is approved by the Commission or its designee, the proposed transferee may not conduct any activities otherwise authorized by the permit. The following procedure shall be followed when requesting approval for transfer of a permit.

(1) Request. Prior to transferring either ownership or operation of a storage facility, the permittee shall file a request for transfer of the permit with the Commission. Such request may not be filed unless a completed Form P-4, signed by both the permittee and the proposed transferee, has been filed with the Commission.

(2) Approval. The Commission, or its designee, shall approve the transfer of a storage facility permit, provided:

(A) the proposed transferee is not the subject of any unsatisfied Commission enforcement order at the time of the request for permit transfer; and

(B) there are no existing violations of any Commission regulation, order, or permit at the storage facility at the time of the request for permit transfer that have been documented by the Commission, or its employees, unless the proposed transferee agrees to correct the violations according to a compliance schedule approved by the Commission, or its designee.

(3) Good cause. Notwithstanding paragraph (2) of this subsection, for good cause shown the Commission or its designee may require public notice and opportunity for hearing prior to taking action on a request for transfer of a permit. Such request may be denied after notice and opportunity for hearing if the Commission or its designee finds that transfer of the permit would not be in the public interest.

(h) Safety. The following safety requirements shall apply to all underground hydrocarbon storage facilities, except as specifically provided otherwise, provided, however, that the provisions of this subsection shall not apply to any hydrocarbon storage well that is out of service and disconnected from all surface piping. Notwithstanding the compliance time periods specified in this subsection, a new storage facility permitted under this section must have all required safety measures and equipment in place before commencement of storage operations at the facility. All storage facilities that are permitted on the effective date of this section must have such safety measures and equipment in place within the period of time specified. Further, until such a facility has all the safety measures and devices required by paragraphs (2) - (7) and (13) - (16) of this subsection in place, the facility must have an attendant on site at all times. Notwithstanding the compliance time periods specified in paragraph (2)(B) of this subsection, no storage well in active service may be operated without a fully functional emergency shutdown valve unless in compliance with specified conditions of paragraph (2)(C) of this subsection.

(1) Monitoring of injection and withdrawal operations. All hydrocarbon injection and withdrawal activities shall be continuously monitored by an individual who is trained and experienced in such activities. Any facility that is unattended during injection and withdrawal activities shall have company personnel on call at all times. On-call personnel must be able to reach the facility within 30 minutes from the time a potential problem at the storage facility is noted by the individual monitoring the injection or withdrawal activities.

(2) Storage wellhead.

(A) The storage wellhead shall be designed, operated, and maintained to contain the contents of the storage well and protect against loss of stored product.

(B) Within five years of the effective date of this section, the operator shall have installed emergency shutdown valves between the storage wellhead and the product and brine surface piping of each hydrocarbon storage well and, if required under paragraph (3) of this subsection, between the storage wellhead and fresh water surface piping of the well. Within one year of the effective date of the section, an operator may request an exception to the storage wellhead configuration or compliance date of this subparagraph and propose an alternative configuration or workover schedule for approval by the Commission or its designee. A storage well that is out of service and is disconnected from surface piping shall be exempt from this requirement until reactivated for active hydrocarbon storage. Emergency shutdown valves shall meet the following requirements.

(i) Each emergency shutdown valve shall be capable of activation at each storage well, at the on-site control center if one exists, at the remote control center if one exists, and at a location that is reasonably anticipated to be accessible to emergency response personnel at any facility that does not have an on-site control center that is attended 24 hours per day.

(ii) Each emergency shutdown valve shall be an automatic fail-closed valve that automatically closes when there is a loss of pneumatic pressure, hydraulic pressure, or power to the valve.

(iii) Each emergency shutdown valve shall be closed and opened at least monthly.

(iv) Each emergency shutdown valve system shall be tested at least twice each calendar year at intervals not to exceed 7 1/2 months. The test shall consist of activating the actuation devices, checking the warning system, and observing the valve closure.

(C) If an emergency shutdown valve system fails to operate as required, the storage well shall be immediately shut in until repairs are completed, unless:

(i) a backup emergency shutdown valve is in operation on the same piping; or

(ii) an attendant is posted at the well site to provide immediate manual shut-in.

(D) The requirements of this paragraph do not apply to underground hydrocarbon storage facilities storing only crude oil.

(3) Product, brine, and fresh water surface piping.

(A) Product surface piping shall be designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well. For facilities with hazardous materials surface piping under the administrative authority of the Safety Division of the Railroad Commission of Texas, for the purposes of this section, product surface piping extends from the wellhead emergency shutdown valve to the first pressure regulation device, including a manual, motor-operated, or emergency shutdown valve.

(B) Brine surface piping shall be designed for the maximum brine wellhead pressure and to transport, under emergency conditions, product to the brine system gas vapor control system described in paragraph (6) of this subsection unless:

(i) a secondary emergency shutdown valve is in operation on the brine surface piping; and

(ii) the brine surface piping between the wellhead emergency shutdown valve and the secondary emergency shutdown valve is designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well.

(C) Fresh water surface piping, if any, must be equipped with a wellhead emergency shutdown valve unless it is:

(i) disconnected from the wellhead; or

(ii) connected to brine surface piping outboard of the wellhead emergency shutdown valve; or

(iii) designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well; and has an internal diameter of less than or equal to two inches; and an attendant is posted at the well site to provide immediate manual shut-in when in use.

(D) Fresh water piping designed for the permitted maximum allowable operating pressure on the hydrocarbon side of the well and with an internal diameter of less than or equal to two inches is exempt from the requirement that an emergency shutdown valve be located on the wellhead or separated from the wellhead by a spool no longer than six feet.

(4) Overfill detection and automatic shut-in methods.

(A) The requirements of this paragraph shall not apply to an underground hydrocarbon storage facility storing only crude oil.

(B) The requirements of this paragraph shall not apply to a storage well that is out of service and disconnected from surface piping until the well is reconnected for hydrocarbon storage.

(C) Within one year of the effective date of this section, each storage cavern shall have at least two of the following redundant devices or methods in operation:

(i) a safety casing or annular tubing string filled with a non-volatile fluid and equipped with a pressure sensor switch set to automatically close all emergency shutdown valves in response to a preset pressure;

(ii) a preset pressure sensor switch or transducer on the brine piping that is set to automatically close all emergency shutdown valves in response to a preset pressure. This pressure sensor or transducer may be used in conjunction with weep hole(s) on a safety string that is concentric with the brine string, or in conjunction with weep hole(s) on the brine string;

(iii) a device on the brine string or brine piping that detects hydrocarbon in the brine by physical or chemical characteristics and that is set to automatically close all emergency shutdown valves in response to hydrocarbon detection;

(iv) an instrument that detects a rapid increase in the brine flow rate indicative of hydrocarbon in the brine and that is set to automatically close all emergency shutdown valves in response to a preset flow rate or differential flow rate; or

(v) an alternate device or method approved by the Commission or its designee.

(5) Leak detectors.

(A) The provisions of subparagraphs (B) - (D) of this paragraph shall not apply to underground hydrocarbon storage facilities storing only crude oil.

(B) A leak detector shall be installed and in operation at the wellhead of each hydrocarbon storage well and at each process and transfer area and each surface vessel area that contains liquid or liquefied hydrocarbons. These leak detectors shall be integrated with the warning system required in paragraph (13)(A) of this subsection.

(C) Leak detectors shall be installed and in operation at four locations that are evenly spaced around the perimeter of the brine pit(s).

(D) Leak detectors shall be tested twice each calendar year at intervals not to exceed 7 1/2 months and, when defective, repaired or replaced within 10 days.

(6) Brine system gas vapor control.

(A) The provisions of this paragraph shall not apply to underground hydrocarbon storage facilities storing only crude oil.

(B) Gas vapor control devices shall be installed and in operation at each brine pit system to ignite or capture hydrocarbon vapors that are heavier than air. Control devices shall consist of at least one of the following:

(i) a flare on the brine system upstream from the brine discharge point;

(ii) a hydrocarbon liquid knockout vessel and degasifier;

(iii) pilot lights on the berm of each brine pit; or

(iv) an alternative method designed to provide a reliable, localized point of ignition to prevent the formation of a vapor cloud.

(C) Brine system gas vapor control systems shall be inspected twice each calendar year at intervals not to exceed 7 1/2 months.

(7) Fire detection devices or methods and fire control systems.

(A) Fire detection devices or methods shall be installed and in operation at all process and transfer areas. Fire detection devices or methods specified in this paragraph shall be integrated with the warning system required in paragraph (13)(A) of this subsection. Fire detection shall consist of at least one of the following:

(i) fire detectors;

(ii) heat sensors, including meltdown and fused devices; or

(iii) camera surveillance at facilities that are attended at an on-site control room 24 hours per day.

(B) Fire detectors shall be tested twice each calendar year at intervals not to exceed 7 1/2 months and, when defective, repaired or replaced within 10 days.

(C) Within three years of the effective date of this section, each storage wellhead in active storage service shall have fire suppression capability designed to aid in personnel rescue and for equipment protection and cooling. Within one year of the effective date of this section, the operator may request an exception to the schedule or fire suppression requirement of this subparagraph and propose an alternative schedule or means of protection from wellhead fire for approval of the Commission or its designee.

(8) Emergency response plan. Each storage facility shall submit to the Commission a written emergency response plan. The plan shall address spills and releases, fires, fire suppression capability, explosions, loss of electricity, and loss of telecommunication services. The plan shall describe the storage facility's emergency response communication system, procedures for coordination of emergency communication and response activities with local emergency planning committees and other local authorities, use of warning systems, procedures for citizen and employee emergency notification and evacuation, and employee training. The initial plan must be designed based upon the existing safety measures at the facility. The plan shall be updated as changes in safety features at the facility occur, or as the Commission or its designee requires. The plan shall include a plat of the facility that shows the location of wells, processing areas, loading racks, brine pits, and other significant features at the site. A copy of the plan shall be provided to the local emergency response planning committee and to any other local governmental entity that submits a written request for a copy of the plan to the operator. Copies of the plan shall also be available at the storage facility and at the company headquarters.

(9) Notification of emergency or uncontrolled release.

(A) Emergency response personnel. Each operator shall notify the county sheriff's office, the county emergency management coordinator, and any other appropriate public officials, which are identified in the emergency response plan, of any emergency that could endanger nearby residents or property. Such emergencies include, but are not limited to, an uncontrolled release of hydrocarbons from a storage well, or a leak or fire at any area of the storage facility. The operator shall give notice as soon as practicable following the discovery of the emergency. At the time of the notice, the operator shall report an assessment of the potential threat to the public.

(B) Commission. The operator shall report to the appropriate Commission district office as soon as practicable any emergency, significant loss of fluids, significant mechanical failure, or other problem that increases the potential for an uncontrolled release. The operator shall file with the Commission within 30 days of the incident a written report on the root cause of the incident. The operator shall file with the Commission within 90 days of the incident a written report that describes the operational changes, if any, that have been or will be implemented to reduce the likelihood of a recurrence of a similar incident. An operator may request that the Commission grant, for good cause, a reasonable amount of additional time to file a written report on the root cause of the incident.

(10) Public education. Each facility operator shall establish a continuing educational program to inform residents within a one-mile radius of a hydrocarbon storage facility of emergency notification and evacuation procedures.

(11) Annual emergency drill. Annually, each operator shall conduct a drill that tests response to a simulated emergency. Written notice of the drill shall be provided to the appropriate Commission district office, the county emergency management coordinator, and the county sheriff's office at least seven days prior to the drill. Local emergency response authorities shall be invited to participate in all such drills. The operator shall file a written evaluation of the drill and plans for improvements with the appropriate district office and the county emergency management coordinator within 30 days after the date of the drill.

(12) Employee safety training.

(A) Each operator shall prepare and implement a plan to train and test each employee at each underground hydrocarbon storage facility on operational safety to the extent applicable to the employee's duties and responsibilities. The facility's emergency response plan shall be included in the training program.

(B) Each operator shall hold a safety meeting with each contractor prior to the commencement of any new contract work at an underground hydrocarbon storage facility. Emergency measures, including safety and evacuation measures specific to the contractor's work, shall be explained in the contractor safety meeting.

(13) Warning systems and alarms.

(A) All leak detectors, fire detectors, heat sensors, pressure sensors, and emergency shutdown instrumentation shall be integrated with warning systems that are audible and visible in the local control room and at any remote control center. The circuitry shall be designed so that failure of a detector or heat sensor, excluding meltdown and fused devices, to function will activate the warning.

(B) A manually operated alarm shall be installed at each attended storage facility. The alarm shall be audible in areas of the facility where personnel are normally located.

(14) Wind socks. At least one wind sock that is visible at any time from any normal work location within the storage facility shall be installed at the facility.

(15) Barriers. Barriers designed to prevent unintended impact by vehicles and equipment shall be placed around above-grade hydrocarbon piping, hydrocarbon process equipment, and surface hydrocarbon storage vessels in areas where vehicles may normally be expected to travel or within 100 feet of a public road.

(16) Wellhead, surface piping, and associated valves. All wellhead equipment, product, fresh water, and brine surface piping, and associated valves shall be designed, installed, and operated in accordance with engineering standards to the expected service conditions to which the piping and equipment will be subjected.

(i) Cavern capacity and configuration.

(1) Crude oil storage. The provisions of this subsection shall not apply to underground hydrocarbon storage facilities where only crude oil is stored.

(2) Before storage operations begin. The capacity and configuration of each hydrocarbon storage cavern (both salt domes and bedded salt) shall be determined by sonar survey before storage operations begin in a newly completed cavern.

(3) Salt domes. The capacity and configuration of each salt dome hydrocarbon storage cavern shall be determined by sonar survey at least once every 10 years.

(4) Bedded salt. The configuration of the roof of each hydrocarbon storage cavern in bedded salt shall be determined by downhole log or an alternate method approved by the Commission or its designee at least once every five years.

(5) Filing results. Sonar and roof monitoring survey results shall be filed with the Commission within 30 days after the survey.

(6) Out-of-service caverns. A sonar or roof monitoring survey is not required for a cavern that is out of service. A sonar or roof monitoring survey shall be performed before any cavern that has been out of service is returned to service, unless the provisions of paragraph (2) of this subsection apply.

(j) Well completion, casing, and cementing. Hydrocarbon storage wells shall be cased and the casing strings cemented to prevent fluids from escaping to the surface or into fresh water strata, or otherwise escaping and causing waste or endangering public safety or the environment.

(1) New wells.

(A) All hydrocarbon storage wells drilled in salt domes after the effective date of this section shall have at least two casing strings cemented into the salt formation. Sufficient cement shall be used to fill the annular space outside the casing from the casing shoe to the ground surface, or from the casing shoe to a point at least 200 feet above the shoe of the previous casing string.

(B) All hydrocarbon storage wells in bedded salt drilled after the effective date of this section shall have all casing strings cemented with sufficient cement to fill the annular space outside each casing string from the casing shoe to the ground surface.

(2) Well completion report. A well completion report shall be filed in accordance with the instructions on the form prescribed by the Commission within 30 days after a storage well is completed and before solution mining to create the cavern begins.

(k) Operating requirements.

(1) Operating pressure. The operating pressure of each hydrocarbon storage well shall not exceed the permitted maximum allowable operating pressure for that well. The permitted maximum allowable operating pressure is that pressure specified in the Commission permit or order, or, if not specified in the permit or order, that pressure stated in the application or the application for amendment to a permit or order. The maximum operating pressure at the shoe of the lowermost cemented casing shall not exceed 0.8 pounds per square inch per foot of depth.

(2) Volume of hydrocarbons stored. The quantity of hydrocarbons stored in a cavern shall not exceed the permitted maximum storage volume for that cavern. The permitted maximum hydrocarbon storage volume is that volume specified in the Commission permit or order, or, if not specified in the permit or order, that volume stated in the application or the application for amendment to a permit or order.

(l) Monitoring requirements.

(1) Pressures. Each hydrocarbon storage well shall be equipped with pressure sensors that continuously monitor and display wellhead pressures on both the product and brine sides of the wellhead at the control room. Each hydrocarbon storage well with a safety string shall be equipped with a pressure sensor and the sensor shall continuously monitor the pressure on the safety string at the wellhead.

(2) Pressure gauges. Each hydrocarbon storage well shall be equipped with gauges on both the brine and hydrocarbon sides of the wellhead.

(3) Volumes injected and withdrawn. The volume of hydrocarbons injected into and withdrawn from each hydrocarbon storage well shall be measured by:

(A) flow meter for each well; or

(B) an alternate method approved by the Commission or its designee.

(4) Measurement performance. The accuracy of hydrocarbon volume measurement devices or methods required under paragraph (3) of this subsection shall be verified at least once each year by a person who is not an officer or employee of the owner or operator, or any affiliate of the owner or operator. For purposes of this section, an affiliate is any person or entity that owns, is owned by, or is under common ownership with the owner or the operator. In the case of meters, verification includes witnessing meter calibration or proving conducted by the owner or operator or an affiliate of the owner or operator.

(5) Data recording. Within three years of the effective date of this section, operators shall have installed and have functioning equipment to electronically record all liquid and gas pressures, volumes, and flow rates at a frequency of at least once per minute, and all actuations of the emergency shutdown valve.

(m) Reporting. The operator shall report maximum wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon storage well and the net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon storage well in accordance with the instructions on the annual report form prescribed by the Commission.

(n) Operations, construction, and maintenance records retention.

(1) Hydrocarbon injection and withdrawal data.

(A) The operator shall retain for at least three months all electronic records of hydrocarbon storage well pressures, flow rates, and hydrocarbon volumes injected into and withdrawn from each well, and the hydrocarbon inventory of each cavern. These electronic data shall be recorded at a frequency of at least once per minute.

(B) The operator shall retain for at least five years the records, reported to the Commission under subsection (m) of this section, of maximum monthly wellhead pressures on the hydrocarbon and brine sides of each hydrocarbon storage well and the monthly net volumes of hydrocarbons injected into and withdrawn from each hydrocarbon storage well. These electronic data shall be recorded at a frequency of at least once per day.

(2) Records retention. The operator shall retain for at least five years the records of measurement performance under subsection (l)(4) of this section; and testing of safety devices under subsection (h) of this section. Records of any test of a safety device required under subsection (h) of this section shall be available for on-site inspection within 10 days of the date of the test.

(3) Construction and maintenance data. The operator shall retain for the life of the facility documents and records pertaining to the drilling, mining, completion, major repairs, and workovers of storage wells and testing of storage well integrity, and shall transfer all such documents and records to any new owner and/or new operator of the facility.

(4) Extension during investigation. Any documents or records that contain information pertinent to the resolution of any pending regulatory enforcement proceeding shall be retained beyond the prescribed retention until the resolution of such proceeding.

(o) Testing and maintenance.

(1) Integrity tests for wells in salt domes with a single casing string. Each hydrocarbon storage well drilled into a salt dome and having a single casing string cemented to the surface shall have the casing inspected by mechanical, ultrasonic, or magnetic methods at least once every five years and after each workover that involves physical changes to the cemented casing string.

(2) Integrity tests for wells other than those in salt domes with a single casing string. Each hydrocarbon storage well shall be tested for integrity prior to being placed into service, at least once every five years, and after each workover that involves physical changes to any cemented casing string. The following requirements apply to all such integrity tests.

(A) A hydrocarbon storage well shall be tested for integrity by the nitrogen-brine interface method or an alternative approved by the Commission, or its designee.

(B) A test procedure shall be filed with the Commission for approval at least 10 days before the test date.

(C) The operator shall notify the district office at least five days prior to conducting any integrity test.

(D) A complete record of each integrity test shall be filed in duplicate with the district office within 30 days after testing is completed. The record shall include a chronology of the test, copies of all downhole logs, storage well completion information, pressure readings, volume measurements, temperature logs and readings, and an explanation of the test results that addresses the precision of the test in terms of a calculated leak rate.

(E) Storage well pressures shall be allowed to stabilize to a rate of change of less than 10 psi in 24 hours before the testing period begins.

(3) Storage wellhead and casing. Storage wellhead components and casing shall be inspected at least once every 10 years for corrosion, cracks, deformations or other conditions that may compromise integrity and that may not be detected by the five-year test. The operator may request an extension of up to five years from the Commission for good cause. Factors the Commission may consider in determining good cause pursuant to this paragraph include by are not limited to the age, location, and configuration of the well; well and facility history; operator compliance record; operator efforts to comply with this subsection; and accuracy of inventory control.

(4) Product, fresh water, and brine surface piping. Within one year of the effective date of this section, the operator shall submit a piping integrity management plan for approval by the Commission or its designee. Within three years of the effective date of this section, or in conjunction with the storage well integrity testing, all product, freshwater, and brine surface piping shall be maintained according to the facility's piping integrity management plan.

(5) Alternative monitoring. An operator may request the Commission or its designee to approve storage well pressure monitoring as an alternative to integrity testing for hydrocarbon storage wells that are out of storage service. An out-of-service storage well must be tested for integrity according to the procedures specified in paragraph (2) of this subsection before it may be returned to storage service.

(p) Plugging.

(1) Plug on abandonment. A hydrocarbon storage well shall be plugged upon permanent abandonment in a manner approved by the Commission or its designee. A proposal for plugging shall be submitted to the Commission in Austin for approval or modification prior to plugging. Following approval of a plugging plan, the operator shall file a notification of intent to plug at least five days prior to commencement of plugging operations. A plugging report shall be filed with the Commission in Austin within 30 days after plugging.

(2) Alternative monitoring. As an alternative to plugging a hydrocarbon storage well that has been permanently deactivated, an operator may request approval by the Commission or its designee of a plan to convert the storage well to a monitor well. A pressure monitoring plan must be submitted to the Commission along with the request to convert the storage well to a monitoring well.

(q) Penalties.

(1) Penalties. Violations of this section may subject the operator to penalties and remedies specified in the Texas Natural Resources Code, Titles 3 and 11, and other statutes administered by the Commission.

(2) Certificate of compliance. The certificate of compliance for any underground hydrocarbon storage facility may be revoked in the manner provided in §3.73 of this title (relating to Pipeline Connection; Cancellation of Certificate of Compliance; Severance).

(r) Applicability of other Commission rules and orders. The owner or operator of an underground hydrocarbon storage facility is not relieved by this section of compliance with any other requirement of Chapters 3, 4, 7, or 8 of this title (relating to Oil and Gas Division; Environmental Protection; Gas Services Division; or Pipeline Safety Regulations).

Source Note: The provisions of this §3.95 adopted to be effective January 1, 1994, 18 TexReg 8871; amended to be effective November 24, 2004, 29 TexReg 10728; amended to be effective January 30, 2007, 32 TexReg 289; amended to be effective July 2, 2012, 37 TexReg 4892