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§ 2132. Production Regulations.

2 CA ADC § 2132BARCLAYS OFFICIAL CALIFORNIA CODE OF REGULATIONS

Barclays Official California Code of Regulations Currentness
Title 2. Administration
Division 3. State Property Operations
Chapter 1. State Lands Commission
Article 3.3. Oil and Gas Production Regulations (Refs & Annos)
2 CCR § 2132
§ 2132. Production Regulations.
(a) Well Completion.
(1) A well-completion program for each well, whether surface or subsea completed, shall be submitted as a part of the drilling program (Refer to Article 3.2, Section 2128(d)(1)) for approval by the Staff. In the event a completion program cannot be provided with the well-drilling program, the lessee shall submit a completion program for Staff approval prior to commencement of the completion work.
(2) The program shall include detailed information and working drawings as appropriate, of the wellhead assembly, surface and downhole production control equipment, and safety system.
(3) Proposals for subsea well completions shall be reviewed and approved by the Staff on an individual well basis.
(4) Wellhead Equipment.
(A) The wellhead equipment associated with each casing string and tubing string and all valves and fittings which may be subjected to wellbore pressure under any condition, shall have a rated working pressure exceeding the maximum anticipated surface pressure to which they may be subjected.
(B) All wellhead equipment, valves and flow lines installed on offshore wells shall be flange or other nonthread connected. All wellhead equipment, valves and flow lines on upland wells that are designed for a working pressure of 2,000 psi or greater shall be flange or other nonthread connected.
(C) Valves shall be installed to permit fluids to be pumped into each casing string. Two master valves shall be installed on any well capable of flowing.
(D) All wellhead equipment shall be tested by a fluid pressure equal to its rated working pressure after installation on a well.
(E) All wellhead components, valves and flow lines in service upon adoption of these regulations are exempted from the requirements in Section 2132(a) (4)(B); except that any modification to existing equipment or piping, unless otherwise approved in writing by the Staff shall be flange or other nonthread connected.
(F) All wellhead equipment, valves and flow lines on any well to be redrilled, recompleted or converted to fluid injection shall comply with the provisions of Sections 2132(a) (4)(A)-(E) above.
(G) All pressure test results shall be recorded on the daily well work report.
(5) Blowout Preventer Removal. If a well is capable of flowing oil or gas, a back-pressure valve or suitable tubing plug shall be installed in the tubing string(s) to seal the bore of the tubing while removing the blowout preventer stack and installing the Christmas tree.
(6) Sealing of Casing -Tubing Annulus. All wells capable of flowing oil or gas shall be equipped with a tubing packer(s) to effectively seal the casing-tubing annulus. All production packers shall be properly tested upon installation.
(7) Perforation and Wireline Operations Under Pressure. All perforation and wireline operations conducted under pressure shall be performed through a lubricator installed on appropriate wireline blowout-prevention equipment. The pressure rating of the lubricator shall be equal to or greater than the maximum possible surface shut-in pressure of the well.
The well shall not be left unattended unless all wellhead flow valves and the wireline blowout preventer are closed in or unless the tools are pulled up into the lubricator and the master valve closed.
(8) Subsurface Safety Valves.
(A) All wells capable of flowing oil or gas shall be equipped with a surface-controlled subsurface safety valve installed in the tubing string(s) at a depth of 100 feet or more below the ocean floor, or ground level for upland wells. Such valve shall be installed in artificial lift wells, unless proof is provided to the Staff that such wells are incapable of flowing. Wells which are presently equipped with direct-controlled subsurface safety valves shall have surface-controlled subsurface safety valves installed the first time the tubing is pulled. The control system for the surface-controlled subsurface safety valves shall be connected to the facility integrated safety-control system, where applicable.
(B) Subsurface safety valves at the time of installation shall conform to the “American Petroleum Institute (API) Specification for Subsurface Safety Valves,” API Spec 14 A, Third Edition, November 1978, or subsequent revisions thereto that are approved by the Staff.
(C) Subsurface safety valves shall be installed, adjusted and maintained in accordance with the “American Petroleum Institute (API) Recommended Practice for Design, Installation and Operation of Subsurface Safety Valve Systems,” API RP 14B, First Edition, October 1973, or subsequent revisions thereto that are approved by the Staff.
(D) Each subsurface safety valve installed in a well shall be tested by the lessee for proper operation each month. The Staff may adjust the testing frequency based upon the performance record of the valve. Permission to increase the testing frequency shall require substantiation by the lessee and written approval by the Staff. The tests may be witnessed and approved by the Staff. If the valve does not operate properly, it shall be repaired or replaced and again tested for proper operation.
(E) When a subsurface safety valve is removed from a well for repair or replacement it shall be replaced immediately or a tubing plug shall be installed before the well is left unattended.
(F) The well history and any subsequent report of workover shall state the type and depth of the subsurface safety valve or tubing plug installed in the well.
(G) Records shall be maintained at the facility or at the nearest onshore office of the lessee. The records shall contain a description and show the present status and past history of each subsurface safety valve or tubing plug, including dates and details of any inspection, testing, repairing, and reinstallation or replacement. The lessee shall submit a copy of such records semiannually to the Staff.
(9) Wellhead Surface Safety Valves.
(A) All wells capable of flowing oil or gas and all artificial lift wells capable of afterflow when the source of power is shut off shall be equipped with an automatic, fail-close, wellhead surface safety valve. High-low pressure sensors shall be located in the flowline close to the wellhead and shall be set to cause shut-in of the valve in the event of abnormally high or low flowline pressures. In addition, each valve shall be connected to the integrated safety control system on the facility.
(B) Wellhead surface safety valves shall be employed in the safety control system on the facility and shall be tested in accordance with the provisions of the “American Petroleum Institute (API) Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface-Safety Systems on Offshore Production Platforms,” API RP 14C, Second Edition, January 1978, or subsequent revisions thereto that are approved by the Staff.
(C) Wellhead surface safety valves at the time of installation shall conform to the “American Petroleum Institute (API) Specification for Wellhead Surface Safety Valves for Offshore Service,” API Spec. 14D, Second Edition, November 1977, as amended by supplement 2, November 1978, or subsequent revisions thereto that are approved by the Staff.
(D) All wellhead surface safety valves shall be tested by the lessee for operation and holding pressure monthly. If the valve fails to test properly, it shall be repaired or replaced and again tested for proper operation. Pressure sensors shall be operated and tested by the lessee for proper pressure settings monthly. The monthly tests may be witnessed and approved by the Staff. Results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee.
(10) Wells on Artificial Lift.
(A) Artificial lift wells not equipped with a wellhead surface safety valve shall have safety devices installed to shut off the source of power in the event of abnormally high or low flowline pressures. The source of power shall be controllable by the integrated safety system.
(B) The safety devices shall be actuated and tested monthly by the lessee. If the device fails to test properly, it shall be repaired or replaced and again tested for proper operation. The monthly tests may be witnessed and approved by the Staff. The results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee.
(11) Production Headers.
(A) All well flowlines shall be equipped with a check valve located downstream at the production header. All check and header valves, as well as any piping that might be subjected to wellhead pressure, shall be of sufficient strength to withstand any possible shut-in wellhead pressure.
(B) The flowline check valve shall be tested for holding pressure monthly by the lessee. If the valve fails to test properly, it shall be repaired or replaced and again tested for proper operation. The monthly tests may be witnessed and approved by the Staff. The results of all tests shall be recorded and maintained at the facility or at the nearest onshore office of the lessee.
(b) Remedial and Well-Maintenance Work.
(1) The lessee shall obtain written approval from the Staff prior to performing remedial work on any well that involves the alteration of its casing or that will result in changing its producing interval. Such work includes, but is not necessarily limited to, casing and liner repair or replacement, squeeze cementing, plugging, perforating, and the installation or removal of bridge plugs and packers.
(A) Each proposal for remedial work shall be accompanied by a statement reflecting the reason for the work and a detailed work and blowout prevention equipment program. The work program also shall include the static formation pore pressure of all zones exposed or to be exposed in the well, the type and densities of circulating fluids to be used, and any other data that is pertinent to well control.
(2) The lessee shall provide written notification to the Staff of its intention to perform nonroutine well-maintenance work on any well. Such work may include, but may not be limited to, formation fracturing, acidization or solvent stimulation, snubbing operations, wireline work resulting in a change of producing interval, any work on a subsea completed well that involves entry of the well, and any other well work that involves a higher than normal degree of risk.
(A) The written notification shall include a description of the work to be performed, the type of blowout prevention equipment and safety equipment to be used, and the anticipated date that the work will commence.
(3) Routine well-maintenance work such as pump changes and wireline work not resulting in a change in the producing interval shall not require advance Staff notification or approval. However, routine well-maintenance work shall be recorded on the lessee's daily operations report and copies of the report shall be provided to the Staff at its request.
(4) Minimum blowout prevention equipment requirements for remedial and well-maintenance work shall be in accordance with the Division of Oil and Gas Manual No. M07 entitled “Oil and Gas Well Blowout Prevention in California,” Second Edition, 1978, or subsequent revisions thereof that are approved by the Staff.
(5) On wells capable of flowing oil or gas, the bore of the tubing string(s) shall be sealed with a back-pressure valve, safety valve or suitable tubing plug during the removal or installation of the Christmas tree.
(6) All perforating and wireline operations conducted under pressure shall be performed through a lubricator installed on appropriate wireline-blowout-prevention equipment. The pressure rating of the lubricator shall be equal to or greater than the maximum possible surface shut-in pressure of the well. The well shall not be left unattended unless all wellhead flow valves and the wireline blowout preventer are closed in, or tools are pulled up into the lubricator and the master valve closed.
(7) Within 60 days after the completion of remedial and nonroutine well-maintenance work, the lessee shall file a history with the Staff that describes the work performed and final condition of the well.
(c) Supervision and Training.
(1) The lessee shall provide full-time onsite company supervision of well completion and other production well work which is performed on any well that may be capable of flowing oil, gas or water. This also includes wireline perforating and any well work performed under pressure.
(2) At least one member of the production well work crew or the production supervisor shall maintain surveillance of the well at all times, unless the well is secured with blowout preventers, bridge plugs, tubing plugs or appropriate valving.
(3) Lessee and contractor supervisory personnel and crew chiefs who are engaged in production well work operations on State leases shall be trained and qualified in well-control equipment, operations and techniques. These persons shall successfully complete a basic well-control course every four years and take a refresher course in well-control each year. The basic and refresher course curriculums shall be submitted to and be approved by the Staff. Written certification shall be filed with the Staff on compliance with these training requirements.
(4) A well control drill plan shall be prepared by the lessee for each well production facility for the training of crews engaged in production well work. The plan shall be submitted to and approved by the Staff.
(5) Well control drills shall be held for each crew on a daily basis until each crew member demonstrates the ability to satisfactorily perform his well control assignment. Thereafter, drills shall be held at least once a week for each crew. All drills shall be recorded on the daily well work report.
(d) Anomalous Casing Annulus Pressure.
(1) The casing annulus pressure(s) on each well shall be checked monthly and a record of the pressure readings shall be maintained at the facility or at the nearest onshore office of the lessee if the facility is notmanned. The lessee shall give immediate written notification to the Staff of the occurrence of an anomalous pressure between casing strings in any well.
(2) The lessee shall investigate to determine the source of any anomalous pressure and, if appropriate, shall seal off the source in a manner approved by the Staff.
(3) Any attempt by the lessee to reduce the surface pressure by producing the fluid from the casing annulus, must include a monthly production test of each annulus.
(e) Subsurface Injection Projects.
(1) All subsurface injection projects proposed on State leases, whether injection is for the purpose of reservoir stimulation or waste disposal, shall require prior approval of the Staff. A lessee requesting approval of an injection project shall provide the Staff with all pertinent geological, engineering, and well data that is requested for the evaluation of the project. The lessee shall also file with the Staff copies of all relevant information furnished to the Division of Oil and Gas.
(2) Recompletion or conversion of a well to fluid injection shall require the prior approval of the Staff.
(3) Within 90 days after the start of injection and annually thereafter, the lessee shall file with the Staff information to confirm that injection is limited to the objective zone. This information shall include, but shall not be limited to, dynamic injection profile surveys, daily injection vol ume and pressure data . In the event that injection is determined not to be restricted to the objective zone, then the lessee shall take corrective action as soon as possible. The well-work program shall be approved in writing by the Staff prior to commencement of the work.
(f) Waste Disposal.
(1) All waste discharged into the ocean from production operations shall be treated so as to comply with the discharge requirements of the appropriate Regional Water Quality Control Board. Oil, tar, or other residuary products of oil, or refuse of any kind from any well or facility, such as circulating fluids that contain substances which are toxic to fish life, and chemicals shall be disposed of on shore in a dumping area in conformance with local regulatory requirements. The lessee shall inform the Staff of the method of waste disposal and any changes that are required to comply with the discharge requirements of the Regional Water Quality Control Board. Refer to Article 3.4, Section 2138, for requirements concerning the disposal of drill cuttings and drilling muds.
(g) Production Facility Safety Equipment and Procedures. Unless otherwise provided for in this Section 2132(g), safety equipment, systems and procedures on offshore production facilities shall be based upon the “American Petroleum Institute (API) Recommend Practice for Analysis, Design, Installation and Testing of Basic Surface Safety Systems on Offshore Production Platforms,” API RP 14C, Second Edition, January 1978, or subsequent revisions thereto that are approved by the Staff.
(1) Integrated Safety-Control System. Each offshore production facility shall be equipped with an approved integrated safety-control system that will cause shut-in of all wells and shut-down of the complete production facility in the event of fire, pipeline failure or other catastrophe. A complete testing of the safety-control system to the satisfaction of the Staff shall be conducted by the lessee every six months and may be witnessed and approved by the Staff.
The integrated safety-control system shall be actuated by the following devices which shall be installed and maintained in an operating condition at all times. The devices shall be tested monthly by the lessee, which tests shall be witnessed and approved by the Staff. The lessee shall maintain records at the production facility or at its nearest onshore office showing the present status and past history of each such device, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.
(A) Emergency manually operated controls to actuate the integrated safety system shall be located on the helicopter deck and on all exit stairway landings leading to the helicopter deck and to all boat landings.
(B) All oil and gas pipelines receiving production from offshore production facilities shall be equipped with high-low-pressure shut-in sensors. The low-pressure sensor shall be set so as to actuate the integrated safety-control system in the event of pipeline failure. The pressure settings shall be determined by pipeline operating characteristics, and shall be set as close as practicable to the normal operating pressure of the pipeline.
(C) All pneumatic, hydraulic, and other shut-in control lines shall be equipped with fusible material at strategic points. Fire-detector systems shall be equipped with devices to actuate the integrated safety-control system.
(D) The automatic gas-detector system shall be so equipped as to actuate the integrated safety-control system at a point not higher than 80% of the lower explosive limit.
(2) Safety Devices on Vessels and Tanks. All production vessels and tanks shall be equipped with safety devices as listed below that will cause shut-in of the wells connected to the vessel or tank. The devices shall be tested monthly by the lessee, which tests shall be witnessed and approved by the Staff. The lessee shall maintain records on the production facility showing the present status and past history of each such device, including dates and details of inspection, testing, repairing, adjustment, and reinstallation or replacement.
(A) All separators shall be equipped with high-low-pressure shut-in sensors and high-low-level shut-in controls.
(B) All pressure surge tanks shall be equipped with a high- and low-pressure shut-in sensor and high-low-level shut-in controls.
(C) Atmospheric surge tanks shall be equipped with a high-level shut-in sensor.
(D) All other hydrocarbon-handling pressure vessels shall be equipped with high-low-pressure shut-in sensors and high-level shut-in controls unless they are determined by the Staff to be otherwise protected.
High-pressure shut-in sensors shall be set no higher than 5% below the rated or designed working pressure, and low-pressure shut-in sensors shall be set no lower than 10% below the lowest pressure in the operating pressure range on all vessels with a rated or designed working pressure of more than 400 psi. On lower pressure vessels, the above percentages shall be used as guidelines for sensor settings considering pressure and operating conditions involved, except that sensor settings shall not be within 5 psi of the rated or designed working pressure or the lowest pressure in the operating pressure range.
All pressure-operated sensors shall be equipped to permit testing with an external pressure source.
(3) Pressure Relief Valves.
(A) All pressure vessels shall be equipped with relief valves connected into a gas vent line. All gas vent line systems shall be equipped with a scrubber or similar separation equipment.
(B) A relief valve shall be set no higher than the safe working pressure of the vessel to which it is attached.
(C) Pilot-operated pressure-relief valves shall be equipped to permit testing with an external pressure source. Spring-loaded pressure relief valves shall either be bench-tested or equipped to permit testing with an external pressure source.
(D) Relief valves shall be tested by the lessee every six months. The lessee shall maintain records on the production facility showing the present status and past history of each relief valve, including dates and details of inspection, testing, repairing, adjustment and reinstallation or replacement.
(4) Firefighting System. A firefighting system shall be installed and maintained in operating condition in accordance with the applicable standards of the National Fire Protection Association.
(A) A fixed automatic water spray system or other system approved by the Staff shall be installed in all wellhead areas and in areas where production handling equipment is located.
(B) A firewater system of rigid pipe with fire-hose stations shall be installed on all levels of the facility.
(C) A system employing chemicals or chemical additives may be used in appropriate areas in lieu of or in addition to a firewater system to provide more effective fire protection and control.
(D) An auxiliary connection to the firewater piping shall be installed at a remote location to supply the firefighting system in case of need.
(E) The firefighting system shall be equipped with reserve water pumps to provide for the operating of the system during routine pump maintenance work and in the event of pump failure. The firewater pumps shall be test-operated weekly and the automatic water spray systems shall be test-operated monthly by the lessee. Testing methods other than the use of water shall be approved by the Staff. Monthly tests of the firewater pumps and of the automatic water spray systems may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office.
(F) Portable fire extinguishers shall be located in the living quarters and in other strategic areas. A record showing the date when fire extinguishers were last inspected, tested, or recharged shall be maintained on the production facility.
(G) A diagram of the firefighting system showing the location of all equipment shall be posted in a prominent place on the production facility.
(H) Fire drills shall be conducted weekly by the supervisor in charge of the production facility. A record showing the date that fire drills were conducted shall be maintained on the production facility for at least one year.
(5) Combustible Gas Detector and Alarm System. An automatic hydrocarbon/combustible gas detector and alarm system shall be installed and maintained, on each offshore production facility, in accordance with the following:
(A) Gas-detection systems shall be installed in all areas containing gas-handling facilities or equipment and in enclosed areas which are classified as hazardous areas as defined in the California Administrative Code, Title 24, Part 3.
(B) All gas-detection systems shall be capable of continuously monitoring for the presence of combustible gas in the areas in which the detection devices are located.
(C) The central control shall be capable of giving an audible alarm at a point not higher that 60 percent of the lower explosive limit.
(D) The central control shall automatically activate the shut-in sequences of the integrated safety control system and emergency equipment at a point not higher than 80 percent of the lower explosive limit.
(E) A diagram of the gas-detection systems showing the location of all gas-detection points shall be posted in a prominent place on the production facility.
(F) The gas detection systems shall be tested monthly by the lessee, which tests may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office.
(6) Hydrogen Sulfide Gas Detection and Precaution. Any offshore production facility that handles production known to contain hydrogen sulfide (H2S) gas shall be equipped and maintained in accordance with following requirements to provide for the safety of personnel:
(A) Hydrogen Sulfide Gas Detection and Alarm System.
1. A separate automatic hydrogen sulfide (H2S) gas detector and alarm system. This equipment shall be capable of sensing a minimum of five parts per million H2S in air, with sensing points located at all enclosed and hazardous areas where gas handling facilities are located, as well as any living quarters and other areas where H2S might accumulate in hazardous quantities. The H2S detection devices shall activate audible and visible alarms when the concentration of H2S reaches 20 parts per million in air.
2. H2S detector ampules or other approved devices shall be available for use by all working personnel. After H2S has been initially detected by any device, frequent inspections of all area of poor ventilation shall be made with a portable H2S-detector instrument.
(B) Contingency Plan. A contingency plan shall be developed for each production facility that handles production known to contain hydrogen sulfide (H2S). The plan shall include the following:
1. General information and physiological responses to H2S and SO2 exposure.
2. Safety procedures, equipment, training, and smoking rules.
3. Procedures for normal operating conditions and for H2S emergency conditions.
4. Responsibilities and duties of personnel for the emergency operating condition.
5. Designation of briefing areas as locations for assembly of personnel during an emergency condition. At least two briefing areas shall be established on each facility. Of these two areas, the one upwind at any given time is the safe briefing area.
6. Evacuation plan.
7. Agencies to be notified in case of an emergency.
8. A list of medical personnel and facilities, including addresses and telephone numbers.
(C) Personnel Training Program.
1. To promote efficient safety procedures, an on-site H2S safety program, which includes a monthly drill and training session, shall be established. Records of attendance shall be maintained on the production facility.
2. Supervisory personnel shall have completed a recognized basic first-aid course and shall be responsible for training of work crews and facility operators. All personnel in the working crew shall have been indoctrinated in basic first-aid procedures applicable to victims of H2S exposure. During on-site training sessions and drills, emphasis shall be placed upon rescue and first aid for H2S victims.
3. Each production facility shall have the following equipment, and the facility operator and each crew member shall be thoroughly familiar with the location and use of these items:
- A first-aid kit sized for the normal working number of personnel.
- Resuscitators, complete with face masks, oxygen bottles, and spare oxygen bottles.
- A Strokes litter or equivalent.
4. All personnel, whether regularly assigned, contracted, or employed on an unscheduled basis, shall be informed as to the hazards of H2S and SO2. They shall also be instructed in the proper use of personnel safety equipment which they may be required to use, informed of H2S detectors and alarms, ventilation equipment, prevailing winds, briefing areas, warning systems, and evacuation procedures.
(D) Personnel Protective Equipment.
1. All personnel on a production facility or aboard marine vessels serving the production facility shall be equipped with proper personnel protective-breathing apparatus. The protective-breathing apparatus used in an H2S environment shall conform to all applicable Occupational Safety and Health Administration regulations as set forth in the Code of Federal Register 29 CFR 1910.134 and American National Standards Institute standards. Optional equipment, such as nose cups and spectacle kits, shall be available for use as needed.
2. A system of breathing-air manifolds, hoses, and masks shall be provided in the briefing areas. A cascade air-bottle system shall be provided to refill individual protective-breathing-apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere. All breathing-air bottles shall be labeled as containing breathing-quality air fit for human usage. The compressor and compressed air system shall comply with 29 CFR 1910.134 (OSHA).
3. The storage locations of protective-breathing apparatus shall be such that they are quickly and easily available to all personnel. Storage locations shall include the following:
- Facility operator's office.
- Each working deck.
- Crew quarters.
- Equipment storage room.
- Designated briefing areas.
- Heliport.
4. Workboats attendant to facility operations shall be equipped with a protective-breathing apparatus for all workboat crew members. Additional protective-breathing apparatus shall be available for evacuees. Whenever possible, boats shall be stationed upwind.
5. Helicopters attendant to facility operations shall be equipped with a protective-breathing apparatus for the pilot.
6. The following additional personnel safety equipment shall be available for use as needed:
- Portable H2S detectors.
- Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas.
- Chalkboards and note pads at convenient locations for communication purposes.
- Bull horns and flashing lights.
- Resuscitators.
(E) Visible Warning System.
1. Wind-direction equipment shall be installed at prominent locations to indicate to all personnel, on or in the immediate vicinity of the production facility, the wind direction at all times for determining safe upwind areas in the event that H2S or SO2 is present in the atmosphere.
2. Operational danger signs shall be displayed from each side of the facility, and a number of rectangular red flags shall be hoisted in a manner visible to watercraft and aircraft.
The signs shall have a minimum width of eight feet and a minimum height of four feet, and shall be painted a high-visibility yellow color with black lettering of a minimum of 12 inches in height, indicating:
“DANGER -HYDROGEN SULFIDE -H2S”
Each flag shall be of a minimum width of three feet and a minimum height of two feet. All signs and flags shall be illuminated under conditions of poor visibility and at night when in use. These signs shall indicate the following operational conditions and requirements:
- When H2S is present, signs shall be displayed.
- When H2S is determined to have reached or exceeded a level of 20 parts per million in environmental areas, protective equipment shall be worn by all personnel in those areas and red flags shall be hoisted. Nonworking personnel and nonessential personnel shall be removed to a safe location, or evacuated as appropriate. Radio communications shall be used to alert all known air-and-watercraft in the immediate vicinity of this condition.
(F) Ventilation Equipment. All ventilation devices shall be explosion-proof when used in areas where H2S may accumulate. Movable ventilation devices shall be provided in work areas and be multidirectional and capable of dispersing H2S or SO2 vapors away from working personnel.
(G) Flare System. The flare system shall be designed to safely gather and burn H2S gas. Flare lines shall be located as far from the other facilities as feasible, in a manner to compensate for wind changes. The flare system shall be equipped with a pilot and an automatic igniter. Backup ignition for each flare shall be provided.
(H) Drilling Operations. Any well drilling operation conducted from a production facility and which will penetrate reservoirs known or expected to contain hydrogen sulfide (H2S) shall follow whatever additional requirements as are set forth in USGS Outer Continental Shelf Standard “Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment,” No. 1 (GSS-OCS) Second Edition, June 1979, or subsequent revisions thereto approved by the Staff.
(I) Remedial and Well Maintenance Operations. Any well remedial or well maintenance operation conducted from a production facility, where the subject well has penetrated reservoirs known to contain hydrogen sulfide, shall follow whatever additional requirements, as may be applicable to that particular job, as are set forth in aforementioned USGS “Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment.”
(J) Notification of Regulatory Agencies. The following agencies shall be notified immediately if H2S has been determined to have reached or exceeded a level of 20 ppm in the environmental area:
1. State Lands Commission.
2. U. S. Coast Guard.
(7) Electrical Equipment and Systems.
(A) An auxiliary electrical power supply shall be installed to provide sufficient emergency power for all electrical equipment required to maintain safety of operation in the event the primary electrical power supply fails. The auxiliary electrical power-supply system shall be tested monthly by the lessee and may be witnessed and approved by the Staff. The lessee shall maintain a record of the tests at the production facility or at its nearest onshore office.
(B) All electrical generators, motors, electric power, control, lighting systems shall be installed, protected, and maintained in accordance with the California Administrative Code, Title 24, Part 3.
(8) Welding Practices and Procedures. The following requirements shall apply to all production facilities during any time in which drilling or producing operations are taking place. The term “welding and burning” is defined to include arc or acetylene welding and arc or acetylene cutting.
(A) All welding and burning shall be minimized by fabrication ashore.
(B) If possible, all welding and burning shall be done in an approved, properly functioning welding room.
(C) If welding or burning is necessary outside the weldingroom it shall be conducted in accordance with welding procedures approved by the Staff, which shall include the following minimum requirements:
1. The lessee's supervisor in charge at the installation shall issue written authorization for the work after he has inspected the area in which the work is to be done. If both drilling and producing operations are taking place, the drilling supervisor and the production supervisor shall both sign this authorization.
2. During all welding and burning operations, a man designated as a “fire watch” shall operate a portable gas detector and shall have in his possession a portable fire extinguisher. In addition, a fire hose shall be laid out to the welding area and it shall remain pressurized to the nozzle during the entire period of welding and burning. He shall inspect the area with the gas detector prior to commencement of the welding or burning. He shall continuously monitor the area and shall cause the welding or burning to cease at any time that conditions become unsafe.
3. If welding or burning must be done on a vessel which has contained a flammable substance, all connections to the vessel shall be broken and displaced or slip blanked, and the vessel shall be thoroughly cleaned and rendered free of such flammable substance and tested for gas before the work begins. Prior to performing hot work on the outside of a vessel, the vessel shall be completely flooded with water.
4. If welding or burning must be done on in-service or connected-up piping that section of pipe shall be isolated by the installation of slip blanks or blind flanges, thoroughly purged and cleaned to render it free of any flammable substance, and tested for gas before the work begins. When welding or burning on an isolated, clean and gas-free piping section, one end must remain open.
5. If welding or burning must be done in confined spaces, the space shall be adequately vented and a continuous source of fresh air shall be supplied while work is in progress. If fresh air is supplied by blowers, they shall be so positioned that the intakes will not pick up exhausted gases, fumes, or vapors.
6. If any welding or burning is done on bulkheads, decks, or overheads, the adjacent, overlying or underlying spaces shall be examined to determine that it is safe for the work to proceed. If deemed advisable, a second “fire watch” shall be employed in the contiguous area.
7. If any welding or burning must be done on structural members, it shall be determined by a competent authority that such welding or burning does not endanger the integrity of the structure.
(h) Pipeline Operations and Maintenance. All oil and gas pipelines on State tide and submerged lands shall be operated and maintained in accordance with the following minimum requirements:
(1) General Requirements.
(A) Each lessee shall establish and maintain current written procedures:
1. To insure the safe operation and maintenance of its pipeline system, in accordance with this Section 2132(h), during normal operations.
2. To be followed during abnormal operations and emergencies.
(B) A lessee shall not operate or maintain its pipeline system at a level of safety lower than that required by Section 2132(h) and the procedures that the lessee is directed to establish under Section 2132(h)(1)(A) above.
(C) Whenever a lessee discovers any conditions that present any immediate hazard to persons, property, or the environment, the lessee shall not operate the affected part of the system until the unsafe condition has been corrected.
(2) Maximum Operating Pressures.
(A) Except for surge pressures and other variations from normal operations, a lessee shall not operate a pipeline at a pressure which exceeds any of the following:
1. The internal design pressure of the pipe as determined in accordance with ANSI Code B31.4 for Liquid Petroleum Transportation Piping Systems and ANSI Code B31.8 for Gas Transmission and Distribution Piping Systems.
2. The design pressure of any other component of the pipeline.
3. Eighty percent of hydrostatic test pressure to which the pipeline has been hydrostatically tested.
(B) A lessee shall not permit the pressure in a pipeline during surges or other variation from normal operations to exceed 110 percent of the maximum allowable operating pressure limit established under Section 2132 (h)(2)(A) above. The lessee shall provide adequate controls and protective equipment to control the pressure within this limit.
(3) Communications. Each lessee shall have a communications system for the transmission of the information required for the safe operation of its pipeline system.
(4) External Corrosion Control. All pipelines shall be cathodically protected to prevent external corrosion. The lessee shall conduct tests annually on all cathodically protected pipelines to assure an adequate level of protection. Cathodic protection rectifiers shall be inspected by a qualified electrical inspector every three months. The output of the rectifiers shall be checked daily. The lessee shall maintain records on the production facility showing the daily output readings and the dates, details of inspection, and repairs to each rectifier.
(5) Internal Corrosion Control. Where corrosion inhibitors are necessary to mitigate internal corrosion, they shall be used in sufficient quantities to protect the entire pipeline. The lessee shall use coupons or other monitoring equipment to determine the effectiveness of the inhibitors. The lessee shall, at intervals not exceeding six months, examine coupons or other corrosion-monitoring equipment to assure effectiveness of any inhibitors used.
(6) Pipeline Inspections.
(A) All unburied oil and gas pipelines shall be visually inspected annually by the lessee for damage, evidence of corrosion, and conditions that may be hazardous to the pipelines.
(B) Where mechanically possible, all oil and gas pipelines shall be inspected annually by the lessee using an electronic survey tool. Upon request of the lessee, the frequency of inspection may be reduced depending upon the degree of corrosion observed.
(C) If it is not mechanically possible to run an electronic survey tool, the lessee shall hydrostatically pressure test each oil and gas pipeline to at least 1.5 times its maximum operating pressure. The test procedure shall be approved by the Staff.
(D) The ocean surface above all pipelines that service offshore facilities shall be inspected a minimum of once each week for indication of leakage, using aircraft or boats. Records of these inspections, including the date, methods, and results of each inspection, shall be maintained by the lessee at its nearest onshore office.
(7) Reports of Inspection. The lessee shall file a report with the Staff describing the testing procedure and results of (1) the annual test of the cathodic protection system on each pipeline and (2) the annual visual and electronic inspection of hydrostatic test of each oil and gas pipeline. The reports shall be filed within 60 days following completion of the work.
(8) Safety Equipment and Procedures.
(A) All oil and gas pipelines receiving production from offshore production facilities shall be equipped with high-low-pressure shut-in sensors and with an automatic shut-in valve located at the offshore facility. The pressure sensors shall be connected so as to actuate the automatic shut-in valves on the pipelines as well as all shut-in devices on input sources to the pipelines. The pressure settings shall be determined by pipeline operating characteristics, and shall be set as close as practicable to the normal operating pressure of the pipeline. The automatic shut-in valves also shall be actuated by the integrated safety-control system of the production facility.
(B) All oil and gas pipelines that deliver production to an onshore production facility shall be equipped with a remote-controlled shut-in valve or check valve at or near the receiving facility.
(C) All oil and gas pipelines that cross an offshore facility which do not deliver production to the facility, and may or may not receive production from the facility, shall be equipped with an automatic shut-in valve to be located in the upstream portion of the pipeline at the facility, so as to prevent uncontrolled flow at the facility. This automatic shut-in valve shall be controllable by the integrated safety-control system of the facility.
(D) Any pipeline that delivers gas to an offshore facility for the purpose of gas lift or other operations shall be equipped with an automatic shut-in valve to be located in the upstream portion of the pipeline at the facility, so as to prevent uncontrolled flow at the facility. This automatic shut-in valve shall be controllable by the integrated safety-control system of the facility.
(E) All oil pumps and gas compressors shall be equipped with high-low-pressure shut-in devices.
(F) All pressure sensors, pressure shut-in devices, and automatic shut-in valves shall be tested monthly by the lessee, and shall be witnessed and approved by the Staff. The lessee shall maintain records on the production facility showing the present status and past history of each device, including dates and details of inspection, testing and repairing, adjustment, and reinstallation or replacement.
Note: Authority cited: Sections 6103, 6108, 6216, 6301 and 6873(d), Public Resources Code; and Section 11152, Government Code. Reference: Sections 6005, 6216, 6301, 6871, 6871.1, 6873(d), Public Resources Code.
This database is current through 12/1/17 Register 2017, No. 48
2 CCR § 2132, 2 CA ADC § 2132
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