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TITLE 16ECONOMIC REGULATION
PART 1RAILROAD COMMISSION OF TEXAS
CHAPTER 3OIL AND GAS DIVISION
RULE §3.95Underground Storage of Liquid or Liquefied Hydrocarbons in Salt Formations

    (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

Cont'd...

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