(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:
(1) Blowout Preventers. (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: | |
Conductor.......................... | ..........................1-Diverter System |
First Surface.......................... | ..........................1-Annular |
| 1-Pipe Rams |
| 1-Blind Ram |
Second Surface.......................... | ..........................1-Annular |
| 2-Pipe Rams |
| 1-Blind Ram |
Intermediate.......................... | ..........................1-Annular |
| 2-Pipe Rams |
| 1-Blind Ram |
2. Subsea Installations: | |
Conductor.......................... | ..........................1-Diverter System |
First Surface.......................... | ..........................1-Annular |
| 1-Pipe Ram |
| 1-Blind Shear Ram |
Second Surface.......................... | ..........................2-Annular |
| 3-Pipe Rams |
| 1-Blind Shear Ram |
Intermediate.......................... | ..........................2-Annular |
| 3-Pipe Rams |
| 1-Blind Shear Ram |
(B) In floating drilling operations a bypass valve located on the bottom of the riser may be employed to direct returns to the ocean floor when the formation competency at the conductor setting depth is not adequate to permit circulation of drilling fluids to the vessel.(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.(2) Closing Unit System. The closing unit system shall incorporate the following general specifications: (A) An accumulator unit having a minimum usable hydraulic fluid operating volume, with pumps inoperative, to close all blowout prevention units and still retain a 50 percent volumetric operating reserve at 1200 psi.(B) A fluid reservoir with a capacity equal to approximately twice the usable fluid capacity of the accumulator system.(C) The capability to close each ram type preventer within 30 seconds. Closing time shall not exceed 30 seconds for annular preventers size 20 inches and smaller, and 45 seconds for annular preventers larger than 20 inches.(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.(F) In addition to the above requirements, closing unit systems for subsea blowout equipment installations shall include the following: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.2. The subsea blowout preventer stack shall contain an accumulator volume sufficient to close one annular-type preventer and to open the riser connection without recharge from the surface.3. The Staff may require that the subsea blowout preventer stack be equipped with an emergency shut-in system that on signal from the surface, will shut in the well in the event the drill vessel loses contact with the stack and the primary blowout prevention control system is lost.(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.
(4) Choke Manifold. A choke manifold shall be installed on the drilling rig and be so located that it is readily accessible to drilling personnel. 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.
(5) Fill-up Line. A fill-up line shall be installed on top of the blowout preventer stack on surface installations and on top of the marine riser on subsea installations.(6) Diverter System. A diverter system shall be installed on the well prior to drilling below the conductor casing for the purpose of directing flowing formation fluids from the well safely away from the rig and personnel. 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 6 B 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.(8) Auxiliary Equipment. (A) The following auxiliary equipment shall be provided and maintained as operationally ready at all times. Any equipment that may be subjected to well pressures shall have a working pressure rating at least equal to the rated working pressure of the blowout preventer stack in use. 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.3. An inside blowout preventer, drill pipe float valve, or drop-in check valve shall be available on the rig floor at all times for use in kick-control and stripping operations. The valve, sub, or profile nipple shall be equipped to screw into any drill string member in use.4. A safety valve shall be readily available on the rig floor and shall be equipped to screw into the casing string that is being run into the well.(B) A subsea test tree shall be used in the blowout preventer stack while performing drill stem or production tests from mobile drilling rigs.(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:
(1) Permanent Abandonment. (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.(B) Isolation of Open Hole from Casing. Where there is open hole below the casing, a cement plug shall be placed in the deepest casing string by 1. or 2. below, or, in the event lost circulation conditions exist or are anticipated, the plug may be placed in accordance with 3. below:1. A cement plug placed by displacement method so as to extend from 100 feet below to 100 feet above the casing shoe.2. A cement retainer with effective back-pressure control set not less than 50 feet, nor more than 100 feet, above the casing shoe with a cement plug calculated to extend from 100 feet below the casing shoe to 50 feet above the retainer.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.(C) Plugging or Isolating Perforated Intervals. A cement plug shall be placed opposite all open perforations not previously squeezed with cement. This plug shall extend from 100 feet below to 100 feet above the perforated interval.(D) Isolation of Zones Behind Uncemented Casing. All oil, gas or fresh water-bearing zones located behind casing in the uncemented portion of the hole shall be squeeze cemented so as to isolate fluids in the strata in which they occur.(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.(F) Junk in Hole or Collapsed Casing. In the event that junk cannot be removed from the hole and the hole below the junk is not properly plugged, cement plugs shall be placed as follows: 1. Sufficient cement shall be squeezed through the junk to isolate the lower oil, gas, or fresh water zones and 100 feet of cement placed on top of the junk.2. If the top of the junk is opposite uncemented casing, the casing annulus immediately above the junk shall be cemented with sufficient cement to insure isolation of the lower zones.(G) Plugging of Casing Stubs. If casing is cut and recovered, a cement plug shall be placed so as to extend from 100 feet within the casing stub to 100 feet above the top of the casing stub. 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.(J) Testing of Plugs. The location and hardness of all cement plugs shall be tested by placement of drill string weight (10,000 pounds minimum) on the plug, and by application of pump circulation. A cement plug placed on top of a previously tested bridge plug or retainer need not be tested.(K) Mud. Each of the respective intervals of the hole between the various plugs shall be filled with mud fluid of sufficient density to exert hydrostatic pressure exceeding the greatest formation pressure encountered while drilling such intervals.(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.(M) Record of Abandonment. All plugging and abandonment operations shall be recorded on the driller's log.(2) Temporary Abandonment(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.(B) The use of a bridge plug to temporarily exclude an interval when recompleting a well is not permitted, unless the Staff approves in advance adequate plans for its future recovery and proper abandonment of the zone. 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.