| (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;
Cont'd... |
