§ 2128. Drilling Regulations.
2 CA ADC § 2128Barclays Official California Code of Regulations
2 CCR § 2128
§ 2128. Drilling Regulations.
(3) Prior to the commencement of drilling operations on any well, the lessee shall obtain all necessary permits and approvals required by all applicable laws and regulations. The lessee shall file copies of those permits and approvals and related documents with the State Lands Commission prior to the commencement of drilling operations. The lessee shall abide by the terms of those permits and approvals, including but not limited to, any required notifications prior to the lessee's commencement of drilling operations.
(b) Field Drilling Rules. When sufficient geological and engineering information has been compiled on a lease from exploratory and initial development well drilling, the lessee may make application to the Staff for the establishment of field drilling rules. After the Staff has established field drilling rules, subsequent development well drilling shall be drilled in accordance with these rules. Field drilling rules may include but may not be limited to those relative to casing setting depths, casing cementing requirements and blowout prevention equipment.
(c) Well Site Investigation. Prior to commencing drilling operations on any well from a mobile drilling rig, the lessee shall investigate the conditions of the ocean floor and near sub-bottom including sediment characteristics in the area of the proposed well site. The investigation shall be adequate to (1) ascertain the presence of shallow geological anomalies and gather other information to be used as an aid in the design of a safe well drilling and casing program, and (2) determine the presence and location of significant cultural resources. A report of the findings and provisions for mitigating any problems disclosed by the investigation shall be provided to and must be approved by the Staff. Where a number of wells are proposed to be drilled, the area of study may be expanded to cover all the well sites. The plan(s) of investigation shall be in accordance with guidelines provided by the Staff.
(A) In all exploratory well drilling proposals, the lessee shall provide in the detailed drilling procedures a description and depth of the possible drilling hazards that might be encountered in drilling the well. The drilling hazards shall include, but may not be limited to, possible unstable bottom sediments, shallow gas-charged sediments, zones of lost circulation, oil and gas bearing zones, and abnormal pressured zones.
(B) In drilling operations using a mobile drilling rig, the lessee shall provide in the detailed drilling procedures an operational program which describes procedures and personnel assignments to be employed for rig and personnel safety while drilling the hole for and running the surface casing string(s). The program shall cover, but may not be limited to, requirements and procedures for testing and use of the diverter system; establishment of safe penetration rates; monitoring of mud returns for indication of gas and loss of circulation; evaluation of drilling breaks; evaluation of severity of gas shows or kicks; stand-by liquid mud and use in well control; emergency plugging of the well; safeguards while removing the drilling riser for running and cementing the casing string(s); precautionary measures for fire prevention; and, emergency movement of drilling rig off location.
(2) The casing setting depths shall be based upon all relevant geological and engineering factors, including the presence of shallow geological anomalies, the presence or absence of hydrocarbons, formation fracture gradients, formation pore pressures, water depth, and zones of lost circulation or of other unusual characteristics. Casing setting depths below the second surface casing shall be justified by calculations of the competency of the preceding casing seat to withstand anticipated mud weights, as well as the pressure generated by simulated well kicks from known or potential gas bearing zones, taking into consideration actual or estimated reservoir pressures, formation fracture gradients, minimum programmed mud weights and anticipated kick volumes.
In situations where formation fracture gradients are not known, a formation leak-off or predetermined equivalent mud weight test shall be conducted to obtain estimated formation fracture gradients for use in the calculations. These tests shall be conducted after drilling a maximum of 50 feet of new hole below the shoe of the second surface casing and intermediate casing strings. Additional tests should be performed as the drilling progresses in order to verify the competency of the formation to withstand anticipated pressures, and to further refine casing setting depths. The results of all the tests shall be recorded on the driller's log and reported to the Staff.
The known and estimated factors and calculations used to determine the casing setting depths, as well as the casing design safety factors and specifications shall be shown in the casing and cementing program required in Section 2128(d)(1).
(4) All casing shall be new pipe or the equivalent and shall be inspected by the lessee in a manner approved by the Staff. The inspection shall be sufficient to detect transverse and longitudinal defects, to determine wall thickness, pipe eccentricity and grade uniformity, and shall include a 100 percent thread check of the exposed threads. Casing inspection reports shall be maintained by the lessee in its district office for a period of five years, and shall be available to the Staff.
(5) Except in cases where casing requirements have been established by field drilling rules or where geological and engineering factors indicate that a different program should be used, the following casing and setting-depth requirements shall be included in all well casing programs. All depths refer to true vertical depth (TVD) below the ocean floor or ground level unless otherwise specified. In order of normal installation the casing strings are identified as conductor, first and second surface, intermediate, and production casing.
(A) Conductor Casing (Referred to as drive or structural casing in USGS Order No. 2). This casing shall be set by drilling, driving, or jetting to a depth of approximately 100 feet below the ocean floor or ground level in order to support unconsolidated sediments and thereby provide hole stability for initial drilling operations. If drilled or jetted in, the fluid circulated to the ocean floor shall be of a type that will not pollute the ocean environment.
(B) First Surface Casing (Referred to as conductor casing in USGS Order No. 2). This casing shall be set at a depth between 300 feet and 500 feet below the ocean floor; provided, however, that this casing shall be set before drilling into shallow formations known to contain oil or gas or, if unknown, upon encountering such formations.
(D) Intermediate Casing. Intermediate casing shall be set in accordance with the requirements of Section 2128(e)(2). Notwithstanding these requirements, the Staff may specify the use and the setting depth of the intermediate casing. Also, protective casing shall be set at any depth below the second surface casing when required by well conditions such as abnormal pressure, loss of circulation, hole problems, and for the protection of productive zones while performing deeper drilling.
A blank liner may be used as intermediate casing provided the existing casing string is of adequate strength for conducting deeper drilling. The top of the liner shall overlap a minimum of 100 feet into the next larger casing string. The lap shall be tested by a fluid entry or pressure test to determine whether a seal between the liner top and next larger string has been achieved. The test shall be recorded on the driller's log. If the test indicates an improper seal, the top of the liner shall be squeezed with cement and retested.
(E) Production Casing. This casing shall be set before completing the well for production. A blank or combination liner may be run and cemented as production casing providing the existing casing string is of adequate strength for the safe conduct of production operations. The overlap requirement and the testing of the seal between the liner top and next larger casing string shall be conducted as specified in Section 2128(e)(5)d for intermediate liners. The surface casing shall not be used as production casing.
(2) The conductor (if drilled or jetted) and surface casing strings shall be cemented with sufficient cement to fill the annular space back to the surface or ocean floor. Cement fill shall be verified by the observation of cement returns. The cementing operation may be considered adequate if cement is circulated to the surface or ocean floor within the range of the calculated hole volume. In the event that cement returns are not obtained or cement channeling occurs during cementing of the surface casing strings, the lessee shall run a temperature and/or cement bond survey and/or pressure test the casing shoe to evaluate the adequacy of the cement job. If the casing string is thereby determined to be inadequately cemented, the lessee shall recement the casing string or perform other operations as approved by the Staff to ensure the competency of the cement job.
(3) The intermediate casing string(s) shall be cemented with sufficient cement to fill the annular space a minimum of 200 feet into the preceding larger casing string. The protective and production casing strings shall be cemented in a manner such that cement will cover or isolate zones of unusually high or low pressure and zones containing hydrocarbons. Sufficient cement shall be used to provide annular fillup at least 500 feet above the zones to be covered or isolated or above the casing shoe in cases where zonal coverage is not required. A cement bond survey shall be run following primary cementing of the intermediate, protective, and production casing strings to aid in determining whether each string is cemented in accordance with this Section 2128(f)(3). If a casing string is thereby determined not be adequately cemented, the lessee shall recement the casing string as necessary to achieve annular fillup and isolation of zones. If following a primary cementing operation, it has been determined without the aid of a cement bond survey that remedial cementing is necessary, the running of such survey may be deferred until after recementing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the staff.
(B) Sufficient time for the cement to reach a compressive strength of at least 500 pounds per square inch for the bottom 20 percent of the casing string. To determine the time that a minimum compressive strength of 500 pounds per square inch has been attained, the operator shall pretest the cement slurry at the projected hole temperature and pressure at the cementing depth in accordance with API recommended procedures.
(g) Pressure Testing of Casing. Prior to drilling out the plug after cementing, all casing strings except the conductor casing shall be pressure tested to at least the minimum pressure shown in the table below. In the event that the cement is under-displaced, the pressure test shall be conducted after drilling out cement to at least the float collar depth. This test shall not exceed 70% of the minimum internal yield pressure for the casing. If during the test, the pressure declines more than 10 percent in 30 minutes, or if there is any indication of a leak, corrective measures shall be taken so that a satisfactory test is obtained.
Minimum Surface Pressure Test (psi)
1,500 or 0.2 psi/ft., whichever is greater
1,500 or 0.2 psi/ft., whichever is greater
Liner and Liner Lap
1,500 or 0.2 psi/ft., whichever is greater
1,500 or 0.2 psi/ft., whichever is greater
All casing pressure tests shall be recorded on the driller's log.
Except as otherwise provided in field drilling rules, all wells drilled into the leased lands shall be directionally surveyed as drilling progresses giving both inclination and azimuth measurements. Directional survey shots shall be taken below the setting depth of the conductor casing string at intervals not exceeding 250 feet during the normal course of drilling and at intervals not exceeding 60 feet in angle changing portions of the hole. A multishot directional survey shall be run at casing setting depths and/or at total depth.
Results of directional and inclination survey shots shall be reported promptly to the Staff. Copies of all composite and multishot directional surveys shall be filed with the Staff.
(i) Blowout Prevention Equipment Requirements. Blowout prevention equipment systems consist of several component systems that function to operate the blowout preventers and to assist in well control under varying rig and well conditions. These systems include the blowout preventers, closing unit, kill and choke lines, choke manifold, fill-up line, diverter, marine riser, and auxiliary equipment.
Blowout prevention equipment shall be installed, used, maintained, and tested in a manner necessary to assure well control throughout the drilling, completion or abandonment of a well.
All portions of a blowout prevention system shall be designed so that alternate methods of well control are available in the event of failure of any one portion of the system. If one component of the system that is vital to well control becomes inoperative, drilling operations shall be suspended as soon as possible without danger to the well until the inoperative equipment is repaired or replaced.
Unless stated otherwise below, the following requirements pertaining to blowout prevention equipment shall apply to both surface and subsea equipment installations.
All blowout prevention systems shall include the following:
(A) There shall be a specified minimum number of annular and ram-type preventers on each casing string as tabulated below. On surface installations one preventer shall be a blind ram and on subsea installations one preventer shall be a blind shear ram. Pipe rams shall be provided to fit the pipe in use. Locking devices shall be provided on all ram-type preventers. On subsea installations a remotely operated or automatic locking system shall be required.
1. Surface Installations:
2. Subsea Installations:
1-Blind Shear Ram
1-Blind Shear Ram
1-Blind Shear Ram
(C) All blowout preventers and wellhead assemblies shall have a working pressure exceeding the anticipated surface pressure to which it may be subjected. The lessee shall submit in the blowout prevention program required in Section 2128(d) (1) the anticipated surface pressure of the well and its method of determination for each casing string.
(D) Notwithstanding the working pressure requirements determined in (1)b above, all blowout preventers that are used while drilling the hole for surface or intermediate casing shall have a minimum working pressure rating of 2000 psi (2M), except for diverter systems or annular preventers used on the conductor.
(D) A dual pump system having a discharge pressure equivalent to the rated working pressure of the closing unit. Each pump system shall have an independent alternate source of power and be equipped with automatic switches that activate the pumps when the closing unit manifold pressure drops below 90 percent of the accumulator operating pressure. With the accumulator system removed from service, each pump system shall be capable of closing the annular preventer on the drill pipe being used, plus be capable of opening the hydraulically operated choke line valve and of obtaining a minimum of 200 psi pressure above accumulator precharge on the closing unit manifold within two minutes or less.
(E) There shall be one master control panel which contains a manifold capable of operating and monitoring all of the functions of the closing unit system. All of the controls and gauges in the panel shall be clearly marked and arranged in the same sequence as the valves and the other equipment in the blowout preventer stack which they control. In addition to the master control panel, there shall be a second “remote” or ‘mini” panel capable of operating all of the functions of the closing unit system. One of the two panels shall be located at the driller's station and the other at least 50 feet from the centerline of the wellbore. Each of the two control panels shall be capable of controlling the hydraulic manifold but the actual hydraulic manifold shall be located away from the rig floor. The driller's control panel shall have a power source independent of the accumulator pump system, or be designed so that in the event of complete destruction of the panel, inter-connecting cable or hose, there would be no interference with the operation of the accumulator pump system.
1. The blowout preventer stack shall be equipped with duplicate subsea control pods, each of which shall contain all of the required pilot valves and regulators necessary to operate all blowout preventer stack functions. The control hose bundles may be hydraulic or electro-hydraulic. If hydraulic, the pilot hoses contained within the bundle shall have a minimum internal diameter of 3/16 inch and the power hose shall have a minimum internal diameter of 1 inch. If electro-hydraulic, the electric signal cables may be run integral with the hydraulic power hose or may be run separately. The hose reels shall be so designed that a minimum of four subsea hydraulic functions are operable while running or pulling the blowout preventer stack.
(3) Kill and Choke Lines. The blowout preventer stack shall contain a drilling spool or equivalent connections in the blowout preventer body to provide for separate kill and choke lines. Each kill and choke line shall have a master valve located next to the stack followed by a control valve. Both valves shall be full-opening. The master valve shall not be used for normal opening or closing on flowing fluids.
On surface installations, the control valve on the choke line shall be remotely controllable. On subsea installations, the valves on both the kill and choke lines shall be hydraulically operated. One of the valves on each line shall be “fail-safe” in the closed position. The kill and choke lines on the subsea installation shall be connected through the surface choke manifold to permit pumping into the well through either line.
All connections for valves and fittings shall be flanged, welded or clamped. All lines, including flexible lines, valves and flow fittings shall have a working pressure rating at least equal to the rated working pressure of the blowout preventer stack in use.
On surface installations the kill line, valves and fittings shall have a minimum diameter of 2 inch nominal. The choke line, valves, and fittings shall have a minimum diameter of 3 inch nominal. On subsea installations both kill and choke line assemblies shall have a minimum diameter of 3 inch nominal.
The choke manifold design shall consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids.
The portion of the manifold subject to well and/or pump pressure shall have a working pressure equal to the rated working pressure of the blowout preventer stack in use. All connections for valves and fittings shall be flanged, welded or clamped.
The choke manifold shall be equipped with a minimum of two adjustable chokes, one of which shall be remotely controlled. These chokes shall be isolated by at least one valve on each side to allow for repairs or replacement. All valves shall be full-opening. There shall be at least one bleed line with a minimum diameter of 3 inch nominal. The lines downstream of the chokes shall have a minimum diameter of 2 inch nominal. All lines shall be securely anchored and connected in such a manner as to permit flow to a mud/gas separator, vent lines, or to production facilities or emergency storage. Two vent lines shall be provided if necessary to accomplish the downwind diversion. The choke manifold shall be equipped with accurate pressure gauges so that all control operations can be properly monitored.
The choke manifold for a subsea installation shall be equipped with duplicate adjustable choke systems to permit control through either the choke or kill line in addition to a remotely controlled adjustable choke, and to provide tie-is for both drilling fluid and high pressure pump systems.
A choke control station shall be provided that includes all monitors necessary to furnish a complete overview of the well control situation.
Low-pressure annular preventers, rotating heads or special diverters may be used for the diversion of well fluids. All such equipment shall be able to pack-off around the kelly, drill string and casing if run through the diverter. There shall be two diverter vent lines to permit diversion of well fluids while minimizing back pressure on the well. All vent lines shall be at least 6 inch nominal diameter unless otherwise justified by engineering analysis. The two vent lines shall be installed in a manner to accomplish downwind diversion. Valves on the vent lines shall be full-opening and so designed that the proper valve automatically opens when the diverter is activated or can be opened by remote control from the driller's control panel. A description and diagram of the diverter system and information justifying the sizing of vent lines shall be included in the blowout prevention program required in Section 2128(d)(1).
(7) Marine Riser. The marine riser system and its component parts that are employed in drilling operations from mobile drilling rigs shall conform to the design, operation, inspection and maintenance specifications set forth in Sections 6B and 11 of the “API Recommended Practices for Blowout Prevention Equipment Systems, API RP 53, First Edition, February 1976, reissued February 1978,” or subsequent revisions thereto that are approved by the Staff.
1. A kelly cock shall be installed below the swivel and a full-opening lower kelly valve shall be installed below the kelly. The lower kelly valve shall have an outer diameter such that it may be run through the blowout preventers and the last casing string cemented in the well. A wrench to fit each valve shall be maintained at a conspicuous location readily accessible to the drilling crew.
2. A full-opening drill pipe safety valve shall be available on the rig floor at all times and shall be equipped to screw into any drill string member in use. This valve shall have an outer diameter such that it may be run through the blowout preventers and the last casing string cemented in the well.
(A) Ram-type blowout preventers and related control equipment used in surface and subsea installations shall be tested at the rated working pressure of the preventer stack, wellhead, or 70% of the internal yield pressure of the casing, whichever is the lesser. Annular-type preventers shall be tested at 70 percent of this pressure requirement. Both types of preventers and related control equipment shall be tested at low pressure, 200-300 psi. These tests shall be performed as follows:
(B) In addition, the subsea blowout prevention system shall be stump-tested on the drilling rig to the applicable rated working pressure before the equipment is installed on the well. The test record shall include the opening and closing times and the hydraulic fluid volumes required for each function.
(D) The blowout preventer equipment pressure testing procedure shall be alternated between control panel stations and shall be conducted at staggered intervals in order to allow each drilling crew to perform the tests. On subsea installations alternate control pods may be used on successive test periods.
(A) Ram-type and annular-type blowout preventers and diverters shall be actuated to test for proper functioning on each round trip of the drill pipe, but not more than once every 24 hours during normal drilling operations. Each choke manifold valve and choke, subsea kill and choke line valve, kelly cock, lower kelly valve, and drill pipe safety valve shall be operated daily.
(C) The actuation of preventers and other remotely controlled equipment shall be alternated between control panel stations and shall be conducted at staggered intervals to allow each drilling crew to operate the equipment. On subsea installations alternate control pods may be used on successive operational tests.
(D) A closing unit pump capability test, and accumulator precharge-pressure and closing tests shall be conducted before testing the blowout preventer stack on a well. The tests shall be performed in accordance with the requirements set forth in Section 5A of the “API Recommended Practices for Blowout Prevention Equipment Systems, API RP 53, First Edition, February 1978,” or subsequent revisions thereof that are approved by the Staff.
(3) Inspection and Maintenance of Blowout Prevention Equipment. All blowout prevention equipment systems shall be inspected and maintained in accordance with the manufacturer's recommended procedures. All systems shall be visually inspected at least once each day. Subsea blowout preventer and riser systems may be inspected by use of divers or television equipment. Any necessary equipment repair or replacement shall be accomplished without delay; however, full consideration shall be given to well safety before starting any work.
(1) The lessee shall provide on-site company supervision (company toolpusher) of drilling operations on a 24-hour basis. At least one member of the drilling crew or the toolpusher shall maintain rig-floor surveillance at all times, unless the well is secured with blowout preventers, bridge plugs, or cement plugs.
(2) Except as provided below in Section 2128(k)(3), the lessee and drilling contractor personnel engaged in drilling operations on State oil and gas leases located on State tide and submerged lands shall be trained and qualified in well-control equipment, operations and techniques in accordance with the provisions of the USGS Outer Continental Shelf Standard “Training and Qualifications of Personnel in Well-Control Equipment and Techniques for Drilling on Offshore Locations,” No. T 1 (GSS-OCS-T1), First Edition, December 1977, and subsequent revisions thereto that are approved by the Staff. Written certification shall be filed with the Staff on compliance with this provision before commencing drilling operations.
(A) A well control drill plan shall be prepared by the lessee for each well drilling proposal and shall be submitted for Staff approval along with the blowout prevention program that is required in Section 2128(d)(1). The plan shall also stipulate the total time allotted for the crew to complete each type of operational drill.
(B) Well control drills shall be held for each crew on a daily basis until each crew demonstrates its ability to effect proper closure of the well within the time established by the well control drill plan. Thereafter, the drills may be held on a weekly basis for each crew as set forth in subsection 3.6 of document GSS-OCS-T1 aforesaid.
(1) When drilling operations are planned which will penetrate reservoirs known or expected to contain hydrogen sulfide (H2S), or in those areas where the presence of H2S is unknown, or upon encountering H2S, the preventive measures and the operating practices set forth in U.S.G.S. Outer Continental Shelf Standard, “Safety Requirements for Drilling Operations in a Hydrogen Sulfide Environment,” No. 1 (GSS-OCS-1) Second Edition, June 1979, or subsequent revisions thereto that are approved by the Staff, shall be followed.
(m) Mud Program. The characteristics, use, and testing of drilling mud properties, and the related procedures to be followed during drilling operations, shall be designed so as to prevent loss of well control. Adequate quantities of mud materials shall be maintained at the drill-site and shall be readily accessible for use in well control.
(A) Before starting out of the hole with the drill pipe, the mud shall be circulated with the drill pipe just off bottom, until the mud is properly conditioned. Proper conditioning requires, at a minimum, circulation to the extent that the annulus volume is displaced to insure that the hole is clean and zonal pressures are being controlled by the mud column. When pulling the drill pipe, the annulus shall be filled with mud so that the mud level does not drop below a calculated depth of 100 feet. The number of stands of drill pipe and drill collars that may be pulled before stopping to fill the hole and their equivalent mud displacement volumes shall be calculated and posted at the driller's station. A mechanical, volumetric, or electronic device shall be utilized for accurate measurement of the amount of mud used to fill the hole.
(A) The lessee shall include in the drilling mud program a tabulation by well depths of the minimum quantities of mud material to be maintained at the drill-site. The minimum quantities of mud material required shall be at least equal to the capacity of the downhole and active surface mud system. Sufficient weight material shall be maintained in order to condition the reserve mud to the maximum density programmed.
Continuous mud-logging equipment shall be employed on all exploratory drilling.
(1) The volume of mud required to fill the hole shall be carefully observed, and if at any time there is an indication of swabbing or influx of formation fluids, the necessary safety device(s) shall be installed on the drill pipe. The drill pipe shall be run to bottom and the mud properly conditioned to stabilize the well. The mud shall not be circulated and conditioned except on or near bottom, unless well conditions prevent the running of pipe to bottom.
(4) All formation fluid that is produced during drlllstem testing shall be directed to the producing or test facilities, and that remaining in the drill string after drillstem testing shall be reverse-circulated from the drill pipe. The mud shall be adequately conditioned prior to pulling the drillstem test tools.
(1) A well shall not be redrilled or deepened unless it is determined that the casing exposed in the well will provide adequate strength for the proposed drilling and for subsequent production operations. Where well conditions permit, a casing inspection survey, indicating remaining wall thickness and internal diameter, shall be run to determine the condition of the casing and whether or not it is of adequate strength.
(2) If it is not possible to run a casing inspection survey, the casing shall be pressure tested to at 70% of minimum internal yield pressure or 1.25 times the anticipated surface pressure that it might be subjected to either during the drilling operations or subsequent production operations (including injection), or to the amount stipulated in Section 2128(g), whichever is greater.
(6) Prior to redrilling or deepening a well the lessee shall demonstrate to the Staff that the casing is adequately cemented above the point of new drilling. In the event it is thereby determined that the casing is not adequately cemented, the lessee shall properly recement the casing. The lessee shall verify the adequacy of the remedial cementing operations by running a cement bond survey or by other methods approved by the Staff.
(8) If a well is to be redrilled or deepened to a zone(s) having a pressure significantly higher or lower than that of the shallower producing zone(s), which drilling might cause lost circulation and thereby endanger the well, the shallower producing zones shall be squeeze cemented or cased and cemented, prior to penetrating the lower zone(s).
(q) Plugging and Abandonment of Wells. Before any work is commenced to abandon any well, the lessee shall file with the Staff a written notice of intention to abandon the well. The notice shall show the condition of the well and proposed method of abandonment. Written approval shall be obtained from the Staff prior to commencement of abandonment operations.
In the case of a newly drilled dry hole or where other approved operations on a well are in progress, the lessee may commence plugging operations by securing oral approval from the Staff as to the abandonment procedure and the time that plugging operations are to begin. Prior to requesting oral approval, the lessee shall furnish the Staff a description of the mechanical condition of the well, an electric log, a description of all oil and gas shows and tests, and any other well data necessary for review of the abandonment procedure. The lessee shall immediately file a written notice with the Staff of its intention to abandon the well in confirmation of the approved abandonment procedure.
The lessee shall plug and abandon all wells in accordance with the following minimum requirements:
(A) Isolation of Zones in Open Hole. In open hole portion of the well, cement plugs shall be spaced to extend from 100 feet below to 100 feet above each oil or gas bearing zone or zone that is productive of hydrocarbons elsewhere in a field, and a cement plug at least 200 feet long shall be placed across the intrazone freshwater-saltwater interface, so as to isolate fluids in the strata in which they are found and to prevent them from migrating into other strata.
3. A permanent type bridge plug set within 150 feet above the casing shoe with 50 feet of cement placed on top of the bridge plug. This plug shall be tested prior to placing subsequent plugs.
(E) Isolating Zones Behind Cemented Casing. Inside cemented casing, a 100 foot cement plug shall be placed above each oil or gas zone and above the shoe of the intermediate or second surface casing. A cement plug at least 200 feet long also shall be placed across the intrazone freshwater-saltwater interface.
1. If the stub extends up into the next larger casing string, then a retainer may be set 50 feet above the top of the stub and cement placed 150 feet below and 50 feet above the retainer. If the foregoing methods cannot be used, a bridge plug shall be set 50 feet above the top of the stub and capped with 50 feet of cement.
2. If the stub is below the next larger string, plugging of the open hole interval above the stub shall be accomplished in accordance with Section 2128(q)(1)(A), and, in addition, a cement plug shall be placed so as to extend from 100 feet below to 100 feet above the casing shoe that is exposed above the stub in accordance with Section 2128(q)(1)(B).
(H) Plugging of Annular Space. No casing annular space that extends to the ocean floor shall be left open to drilled hole below. If this condition exists, 200 feet of the annulus immediately above the shoe of the preceding casing string shall be plugged with cement. If an uncemented inner casing string is cut and recovered to accomplish this requirement, the casing stub shall be plugged in accordance with Section 2128(q)(1)(G).
(I) Surface Plug Requirement. A cement plug of at least 100 feet, with the top of the plug not more than 150 feet or less than 50 feet below the ocean floor, shall be placed in the well. Prior to the placement of the surface plug all inside casing strings which are uncemented at the surface plugging depth shall be cut and recovered. Casing cutting methods shall be employed that will not damage the well casing so as to prevent reentry of the well.
(L) Clearance of Location. All casing and conductor shall be severed and removed from not more than 5 feet below the ocean floor, unless other plans are approved by the Staff. The ocean floor shall be cleared of any other obstructions. A method shall be employed to sever or cut the casing that will not damage the well casing so as to prevent reentry of the well.
(A) Any drilling well which is to be temporarily abandoned shall be mudded and cemented as required for permanent abandonment except that the requirements of Section 2128(q)(1), (E), (H), (I), and (L) shall thereupon be deferred. When casing extends above the ocean floor, a mechanical bridge plug (retrievable or permanent) shall be set in the casing between 15 and 200 feet below the ocean floor.
(3) Within 60 days following the completion, abandonment, or the suspension of operations of any well, the lessee shall file with the Staff copies of all logs, including electric logs, surveys, drilling records, well histories, core records and related information as measured and recorded for the wells drilled by the lessee into the leased lands.
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 11/24/23 Register 2023, No. 47.
Cal. Admin. Code tit. 2, § 2128, 2 CA ADC § 2128
|End of Document|