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(continued)
(iii) Elementary electrical schematic of any platform safety shutdown system with a functional legend.
(5) Certification that the design for the mechanical and electrical systems to be installed was approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Supervisor certifying that the new installations conform to the approved designs of this subpart; and
(6) Design and schematics of the installation and maintenance of all fire- and gas-detection systems including the following:
(i) Type, location, and number of detection heads;
(ii) Type and kind of alarm, including emergency equipment to be activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including the electric power supply.
[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. Redesignated at 63 FR 29479, May 29, 1998, as amended at 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002]
§ 250.1629 Additional production and fuel gas system requirements.
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(a) General. Lessees shall comply with the following production safety system requirements (some of which are in addition to those contained in §250.1628 of this part).
(b) Design, installation, and operation of additional production systems, including fuel gas handling safety systems. (1) Pressure and fired vessels must be designed, fabricated, and code stamped in accordance with the applicable provisions of sections I, IV, and VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. Pressure and fired vessels must have maintenance inspection, rating, repair, and alteration performed in accordance with the provisions of the American Petroleum Institute's Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration, API 510 (except Sections 6.5 and 8.5), which is incorporated by reference in §250.198.
(i) Pressure safety relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. The safety relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valves shall be set no higher than the maximum-allowable working pressure of the vessel. All safety relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition sources.
(ii) The lessee shall use pressure recorders to establish the operating pressure ranges of pressure vessels in order to establish the pressure-sensor settings. Pressure-recording charts used to determine operating pressure ranges shall be maintained by the lessee for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Supervisor. The high-pressure sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below (15 percent or 5 psi, whichever is greater) the safety relief valve's set pressure to assure that the high-pressure sensor sounds an alarm before the safety relief valve starts relieving. The low-pressure sensor shall sound an alarm no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range.
(2) Engine exhaust. You must equip engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2c(4) (incorporated by reference as specified in §250.198). Exhaust piping from diesel engines must be equipped with spark arresters.
(3) Firefighting systems. Firefighting systems shall conform to subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, and shall be subject to the approval of the District Supervisor. Additional requirements shall apply as follows:
(i) A firewater system consisting of rigid pipe with firehose stations shall be installed. The firewater system shall be installed to provide needed protection, especially in areas where fuel handling equipment is located.
(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during platform shut-in time. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Supervisor;
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Supervisor determines that the use of a chemical system provides equivalent fire-protection control; and
(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.
(4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) sensors shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated, enclosed classified areas. Adequate ventilation is defined as ventilation that is sufficient to prevent accumulation of significant quantities of vapor-air mixture in concentrations over 25 percent of the lower explosive limit. One approved method of providing adequate ventilation is a change of air volume each 5 minutes or 1 cubic foot of air-volume flow per minute per square foot of solid floor area, whichever is greater. Enclosed areas (e.g., buildings, living quarters, or doghouses) are defined as those areas confined on more than four of their six possible sides by walls, floors, or ceilings more restrictive to air flow than grating or fixed open louvers and of sufficient size to allow entry of personnel. A classified area is any area classified Class I, Group D, Division 1 or 2, following the guidelines of API RP 500, or any area classified Class I, Zone 0, Zone 1, or Zone 2, following the guidelines of API RP 505.
(ii) All detection systems shall be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas concentration levels shall be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility that are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(iv) The District Supervisor may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems must be an approved type, designed and installed according to API RP 14C, API RP 14G, and either API RP 14F or API RP 14FZ (the preceding four documents incorporated by reference as specified in §250.198).
(c) General platform operations.Safety devices shall not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing procedures. Only the minimum number of safety devices shall be taken out of service. Personnel shall monitor the bypassed or blocked out functions until the safety devices are placed back in service. Any safety device that is temporarily out of service shall be flagged by the person taking such device out of service.
[53 FR 10690, Apr. 1, 1988, as amended at 61 FR 60026, Nov. 26, 1996. Redesignated at 63 FR 29479, May 29, 1998, as amended at 64 FR 72794, Dec. 28, 1999; 65 FR 219, Jan. 4, 2000; 67 FR 51760, Aug. 9, 2002; 68 FR 43298, July 22, 2003; 70 FR 7403, Feb. 14, 2005]
§ 250.1630 Safety-system testing and records.
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(a) Inspection and testing. You must inspect and successfully test safety system devices at the interval specified below or more frequently if operating conditions warrant. Testing must be in accordance with API RP 14C, Appendix D (incorporated by reference as specified in §250.198). For safety system devices other than those listed in API RP 14C, Appendix D, you must utilize the analysis technique and documentation specified therein for inspection and testing of these components, and the following:
(1) Safety relief valves on the natural gas feed system for power plant operations such as pressure safety valves shall be inspected and tested for operation at least once every 12 months. These valves shall be either bench tested or equipped to permit testing with an external pressure source.
(2) The following safety devices (excluding electronic pressure transmitters and level sensors) must be inspected and tested at least once each calendar month, but at no time may more than 6 weeks elapse between tests:
(i) All pressure safety high or pressure safety low, and
(ii) All level safety high and level safety low controls.
(3) The following electronic pressure transmitters and level sensors must be inspected and tested at least once every 3 months, but at no time may more than 120 days elapse between tests:
(i) All PSH or PSL, and
(ii) All LSH and LSL controls.
(4) All pumps for firewater systems shall be inspected and operated weekly.
(5) All fire- (flame, heat, or smoke) and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner.
(6) Prior to the commencement of production, the lessee shall notify the District Supervisor when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Supervisor upon commencement of production in order that a complete inspection may be conducted.
(b) Records. The lessee shall maintain records for a period of 2 years for each safety device installed. These records shall be maintained by the lessee at the lessee's field office nearest the OCS facility or another location conveniently available to the District Supervisor. These records shall be available for MMS review. The records shall show the present status and history of each safety device, including dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.
[56 FR 32100, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998, as amended at 67 FR 51761, Aug. 9, 2002]
§ 250.1631 Safety device training.
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Prior to engaging in production operations on a lease and periodically thereafter, personnel installing, inspecting, testing, and maintaining safety devices shall be instructed in the safety requirements of the operations to be performed; possible hazards to be encountered; and general safety considerations to be taken to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available for MMS review.
§ 250.1632 Production rates.
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Each sulphur deposit shall be produced at rates that will provide economic development and depletion of the deposit in a manner that would maximize the ultimate recovery of sulphur without resulting in waste (e.g., an undue reduction in the recovery of oil and gas from an associated hydrocarbon accumulation).
§ 250.1633 Production measurement.
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(a) General. Measurement equipment and security procedures shall be designed, installed, used, maintained, and tested so as to accurately and completely measure the sulphur produced on a lease for purposes of royalty determination.
(b) Application and approval. The lessee shall not commence production of sulphur until the Regional Supervisor has approved the method of measurement. The request for approval of the method of measurement shall contain sufficient information to demonstrate to the satisfaction of the Regional Supervisor that the method of measurement meets the requirements of paragraph (a) of this section.
§ 250.1634 Site security.
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(a) All locations where sulphur is produced, measured, or stored shall be operated and maintained to ensure against the loss or theft of produced sulphur and to assure accurate and complete measurement of produced sulphur for royalty purposes.
(b) Evidence of mishandling of produced sulphur from an offshore lease, or tampering or falsifying any measurement of production for an offshore lease, shall be reported to the Regional Supervisor as soon as possible but no later than the next business day after discovery of the evidence of mishandling.
Subpart Q—Decommissioning Activities
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Authority: 43 U.S.C. 1331 et seq.
Source: 67 FR 35406, May 17, 2002, unless otherwise noted.
General
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§ 250.1700 What do the terms “decommissioning”, “obstructions”, and “facility” mean?
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(a) Decommissioning means:
(1) Ending oil, gas, or sulphur operations; and
(2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of MMS and other agencies that have jurisdiction over decommissioning activities.
(b) Obstructions means structures, equipment, or objects that were used in oil, gas, or sulphur operations or marine growth that, if left in place, would hinder other users of the OCS. Obstructions may include, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables.
(c) Facility means any installation other than a pipeline used for oil, gas, or sulphur activities that is permanently or temporarily attached to the seabed on the OCS. Facilities include production and pipeline risers, templates, pilings, and any other facility or equipment that constitutes an obstruction such as jumper assemblies, termination skids, umbilicals, anchors, and mooring lines.
[67 FR 35406, May 17, 2002; 67 FR 66047, Oct. 30, 2002]
§ 250.1701 Who must meet the decommissioning obligations in this subpart?
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(a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and until each obligation is met.
(b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met.
(c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way.
§ 250.1702 When do I accrue decommissioning obligations?
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You accrue decommissioning obligations when you do any of the following:
(a) Drill a well;
(b) Install a platform, pipeline, or other facility;
(c) Create an obstruction to other users of the OCS;
(d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction;
(e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an obstruction; or
(f) Re-enter a well that was previously plugged according to this subpart.
§ 250.1703 What are the general requirements for decommissioning?
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When your facilities are no longer useful for operations, you must:
(a) Get approval from the appropriate District Supervisor before decommissioning wells and from the Regional Supervisor before decommissioning platforms and pipelines or other facilities;
(b) Permanently plug all wells;
(c) Remove all platforms and other facilities;
(d) Decommission all pipelines;
(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and
(f) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.
§ 250.1704 When must I submit decommissioning applications and reports?
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You must submit decommissioning applications and receive approval and submit subsequent reports according to the table in this section.
Decommissioning Applications and Reports Table
------------------------------------------------------------------------
Decommissioning applications
and reports When to submit Instructions
------------------------------------------------------------------------
(a) Initial platform removal In the Pacific OCS Include
application [not required in Region or Alaska OCS information
the Gulf of Mexico OCS Region, submit the required under
Region]. application to the §
Regional Supervisor 250.1726.
at least 2 years
before production is
projected to cease.
(b) Final removal application Before removing a Include
for a platform or other platform or other information
facility. facility in the Gulf required under
of Mexico OCS Region, §
or not more than 2 250.1727.
years after the
submittal of an
initial platform
removal application
to the Pacific OCS
Region and the Alaska
OCS Region.
(c) Post-removal report for a Within 30 days after Include
platform or other facility. you remove a platform information
or other facility. required under
§
250.1729.
(d) Pipeline decommissioning Before you Include
application. decommission a information
pipeline. required under
§
250.1751(a) or
§
250.1752(a), as
applicable.
(e) Post-pipeline Within 30 days after Include
decommissioning report. you decommission a information
pipeline. required under
§
250.1753.
(f) Site clearance report for Within 30 days after Include
a platform or other facility. you complete site information
clearance required under
verification §
activities. 250.1743(b).
(g) Form MMS-124, Application (1) Before you Include
for Permit to Modify temporarily abandon information
(formerly Sundry Notices and or permanently plug a required under
Reports on Wells). well or zone. §§
250.1712 and
250.1721.
(2) Within 30 days Include
after you plug a well. information
required under
§
250.1717.
(3) Before you install Refer to §
a subsea protective 250.1722(a).
device.
(4) Within 30 days Include
after you complete a information
protective device required under
trawl test. §
250.1722(d).
(5) Before you remove Refer to §
any casing stub or 250.1723.
mud line suspension
equipment and any
subsea protective
device.
(6) Within 30 days Include
after you complete information
site clearance required under
verification §
activities. 250.1743(a).
------------------------------------------------------------------------
[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66047, Oct. 30, 2002]
Permanently Plugging Wells
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§ 250.1710 When must I permanently plug all wells on a lease?
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You must permanently plug all wells on a lease within 1 year after the lease terminates.
§ 250.1711 When will MMS order me to permanently plug a well?
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MMS will order you to permanently plug a well if that well:
(a) Poses a hazard to safety or the environment; or
(b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities.
§ 250.1712 What information must I submit before I permanently plug a well or zone?
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Before you permanently plug a well or zone, you must submit form MMS–124, Application for Permit to Modify, to the appropriate District Supervisor and receive approval. A request for approval must contain the following information:
(a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil, gas, or sulfur;
(b) Recent well test data and pressure data, if available;
(c) Maximum possible surface pressure, and how it was determined;
(d) Type and weight of well-control fluid you will use;
(e) A description of the work; and
(f) A current and proposed well schematic and description that includes:
(1) Well depth;
(2) All perforated intervals that have not been plugged;
(3) Casing and tubing depths and details;
(4) Subsurface equipment;
(5) Estimated tops of cement (and the basis of the estimate) in each casing annulus;
(6) Plug locations;
(7) Plug types;
(8) Plug lengths;
(9) Properties of mud and cement to be used;
(10) Perforating and casing cutting plans;
(11) Plug testing plans;
(12) Casing removal (including information on explosives, if used);
(13) Proposed casing removal depth; and
(14) Your plans to protect archaeological and sensitive biological features, including anchor damage during plugging operations, a brief assessment of the environmental impacts of the plugging operations, and the procedures and mitigation measures you will take to minimize such impacts.
[67 FR 35406, May 17, 2002; 67 FR 66048, Oct. 30, 2002]
§ 250.1713 Must I notify MMS before I begin well plugging operations?
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You must notify the appropriate District Supervisor at least 48 hours before beginning operations to permanently plug a well.
§ 250.1714 What must I accomplish with well plugs?
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You must ensure that all well plugs:
(a) Provide downhole isolation of hydrocarbon and sulphur zones;
(b) Protect freshwater aquifers; and
(c) Prevent migration of formation fluids within the wellbore or to the seafloor.
§ 250.1715 How must I permanently plug a well?
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(a) You must permanently plug wells according to the table in this section. The District Supervisor may require additional well plugs as necessary.
Permanent Well Plugging Requirements
----------------------------------------------------------------------------------------------------------------
If you have_ Then you must use_
----------------------------------------------------------------------------------------------------------------
(1) Zones in open hole...................................... Cement plug(s) set from at least 100 feet below
the bottom to 100 feet above the top of oil, gas,
and fresh-water zones to isolate fluids in the
strata.
(2) Open hole below casing.................................. (i) A cement plug, set by the displacement method,
at least 100 feet above and below deepest casing
shoe;
(ii) A cement retainer with effective back-
pressure control set 50 to 100 feet above the
casing shoe, and a cement plug that extends at
least 100 feet below the casing shoe and at least
50 feet above the retainer; or
(iii) A bridge plug set 50 feet to 100 feet above
the shoe with 50 feet of cement on top of the
bridge plug, for expected or known lost
circulation conditions.
(3) A perforated zone that is currently open and not (i) A method to squeeze cement to all
previously squeezed or isolated. perforations;
(ii) A cement plug set by the displacement method,
at least 100 feet above to 100 feet below the
perforated interval, or down to a casing plug,
whichever is less; or
(iii) If the perforated zones are isolated from
the hole below, you may use any of the plugs
specified in paragraphs (a)(3)(iii)(A) through
(E) of this section instead of those specified in
paragraphs (a)(3)(i) and (a)(3)(ii) of this
section.
(A) A cement retainer with effective back-pressure
control set 50 to 100 feet above the top of the
perforated interval, and a cement plug that
extends at least 100 feet below the bottom of the
perforated interval with at least 50 feet of
cement above the retainer;
(B) A bridge plug set 50 to 100 feet above the top
of the perforated interval and at least 50 feet
of cement on top of the bridge plug;
(C) A cement plug at least 200 feet in length, set
by the displacement method, with the bottom of
the plug no more than 100 feet above the
perforated interval;
(D) A through-tubing basket plug set no more than
100 feet above the perforated interval with at
least 50 feet of cement on top of the basket
plug; or
(E) A tubing plug set no more than 100 feet above
the perforated interval topped with a sufficient
volume of cement so as to extend at least 100
feet above the uppermost packer in the wellbore
and at least 300 feet of cement in the casing
annulus immediately above the packer.
(4) A casing stub where the stub end is within the casing... (i) A cement plug set at least 100 feet above and
below the stub end;
(ii) A cement retainer or bridge plug set at least
50 to 100 feet above the stub end with at least
50 feet of cement on top of the retainer or
bridge plug; or
(iii) A cement plug at least 200 feet long with
the bottom of the plug set no more than 100 feet
above the stub end.
(5) A casing stub where the stub end is below the casing.... A plug as specified in paragraph (a)(1) or (a)(2)
of this section, as applicable.
(6) An annular space that communicates with open hole and A cement plug at least 200 feet long set in the
extends to the mud line. annular space. For a well completed above the
ocean surface, you must pressure test each casing
annulus to verify isolation.
(7) A subsea well with unsealed annulus..................... A cutter to sever the casing, and you must set a
stub plug as specified in paragraphs (a)(4) and
(a)(5) of this section.
(8) A well with casing...................................... A cement surface plug at least 150 feet long set
in the smallest casing that extends to the mud
line with the top of the plug no more than 150
feet below the mud line.
(9) Fluid left in the hole.................................. A fluid in the intervals between the plugs that is
dense enough to exert a hydrostatic pressure that
is greater than the formation pressures in the
intervals.
(10) Permafrost areas....................................... (i) A fluid to be left in the hole that has a
freezing point below the temperature of the
permafrost, and a treatment to inhibit corrosion;
and
(ii) Cement plugs designed to set before freezing
and have a low heat of hydration.
----------------------------------------------------------------------------------------------------------------
(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:
(1) A pipe weight of at least 15,000 pounds on the plug; or
(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Supervisor may require you to tests other plug(s).
[67 FR 35406, May 17, 2002; 67 FR 44265, July 1, 2002; 67 FR 66048, Oct. 30, 2002]
§ 250.1716 To what depth must I remove wellheads and casings?
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(a) Unless the District Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at least 15 feet below the mud line.
(b) The District Supervisor may approve an alternate removal depth if:
(1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers, and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
§ 250.1717 After I permanently plug a well, what information must I submit?
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Within 30 days after you permanently plug a well, you must submit form MMS–124, Application for Permit to Modify (subsequent report), to the appropriate District Supervisor, and include the following information:
(a) Information included in §250.1712 with a final well schematic;
(b) Description of the plugging work;
(c) Nature and quantities of material used in the plugs; and
(d) If you cut and pulled any casing string, the following information:
(1) A description of the methods used (including information on explosives, if used);
(2) Size and amount of casing removed; and
(3) Casing removal depth.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
Temporary Abandoned Wells
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§ 250.1721 If I temporarily abandon a well that I plan to re-enter, what must I do?
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You may temporarily abandon a well when it is necessary for proper development and production of a lease. To temporarily abandon a well, you must do all of the following:
(a) Submit form MMS–124, Application for Permit to Modify, and the applicable information required by §250.1712 to the appropriate District Supervisor and receive approval;
(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in §250.1715, except for §250.1715 (a)(8). You do not need to sever the casings, remove the wellhead, or clear the site;
(c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casing string, unless the casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement plug to extend below the casing shoe into the open hole;
(d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing. The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. MMS may consider approving alternate requirements for subsea wells case-by-case;
(e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according to U.S. Coast Guard (USCG) requirements; and
(f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or other obstructions remaining above the seafloor by using one of the following methods, as approved by the Regional or District Supervisor:
(1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation;
(2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or
(3) A subsea protective device that meets the requirements in §250.1722.
(g) Within 30 days after you temporarily plug a well, you must submit form MMS–124, Application for Permit to Modify (subsequent report), and include the following information:
(1) Information included in §250.1712 with a well schematic;
(2) Information required by §250.1717(b), (c), and (d); and
(3) A description of any remaining subsea wellheads, casing stubs, mudline suspension equipment, or other obstructions that extend above the seafloor.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1722 If I install a subsea protective device, what requirements must I meet?
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If you install a subsea protective device under §250.1721(f)(3), you must install it in a manner that allows fishing gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.
(a) Use form MMS–124, Application for Permit to Modify to request approval from the appropriate District Supervisor to install a subsea protective device.
(b) The protective device may not extend more than 10 feet above the seafloor (unless MMS approves otherwise).
(c) You must trawl over the protective device when you install it (adhere to the requirements at §250.1741 (d) through (h)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District Supervisor within 5 days and perform remedial action within 30 days of the trawl;
(d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Supervisor using form MMS–124, Application for Permit to Modify, that includes the following:
(1) The date(s) the trawling test was performed and the vessel that was used;
(2) A plat at an appropriate scale showing the trawl lines;
(3) A description of the trawling operation and the net(s) that were used;
(4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl;
(5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion of any snag removals requiring diver assistance; and
(6) A letter signed by your authorized representative stating that he/she witnessed the trawling test.
(e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark the site with a buoy installed according to the USCG requirements.
(f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or to permanently plug the well.
(g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths less than 300 feet remain protected.
(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least annually.
(2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line suspension equipment, or the trawl, notify the appropriate District Supervisor within 5 days, and perform the necessary remedial work within 30 days of discovery of the problem.
(3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method used and a description of any remedial work you will perform or have performed.
(h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use either:
(1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR part 67 (or its successor); or
(2) A design and installation method that has been proven successful by trawl testing of previous protective devices of the same design and installed in areas with similar bottom conditions.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1723 What must I do when it is no longer necessary to maintain a well in temporary abandoned status?
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If you or MMS determines that continued maintenance of a well in a temporary abandoned status is not necessary for the proper development or production of a lease, you must:
(a) Promptly and permanently plug the well according to §250.1715;
(b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit a request for approval to perform such work to the appropriate District Supervisor using form MMS–124, Application for Permit to Modify; and
(c) Clear the well site according to §250.1740 through §250.1742.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
Removing Platforms and Other Facilities
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§ 250.1725 When do I have to remove platforms and other facilities?
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(a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates, unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms, well jackets, single-well caissons, and pipeline accessory platforms.
(b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional Supervisor for approval and include the information listed in §250.1727.
(c) You must remove a platform or other facility according to the approved application.
(d) You must flush all production risers with seawater before you remove them.
(e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations.
§ 250.1726 When must I submit an initial platform removal application and what must it include?
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An initial platform removal application is required only for leases and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS Region. It must include the following information:
(a) Platform or other facility removal procedures, including the types of vessels and equipment you will use;
(b) Facilities (including pipelines) you plan to remove or leave in place;
(c) Platform or other facility transportation and disposal plans;
(d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the impacts; and
(e) A projected decommissioning schedule.
[67 FR 35406, May 17, 2002; 67 FR 66049, Oct. 30, 2002]
§ 250.1727 What information must I include in my final application to remove a platform or other facility?
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You must submit a final application to remove a platform or other facility to the Regional Supervisor for approval. This requirement applies to leases in all MMS Regions. If you are proposing to use explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the application. Include the following information in the final removal application, as applicable:
(a) Identification of the applicant including:
(1) Lease operator/pipeline right-of-way holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification of the structure you are removing including:
(1) Platform Name/MMS Complex ID Number;
(2) Location (lease/right-of-way, area, block, and block coordinates);
(3) Date installed (year);
(4) Proposed date of removal (Month/Year); and
(5) Water depth.
(c) Description of the structure you are removing including:
(1) Configuration (attach a photograph or a diagram);
(2) Size;
(3) Number of legs/casings/pilings;
(4) Diameter and wall thickness of legs/casings/pilings;
(5) Whether piles are grouted inside or outside;
(6) Brief description of soil composition and condition;
(7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and
(8) The maximum removal lift weight and estimated number of main lifts to remove the structure.
(d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure.
(e) Identification of the purpose, including:
(1) Lease expiration/right-of-way relinquishment date; and
(2) Reason for removing the structure.
(f) A description of the removal method, including:
(1) A brief description of the method you will use;
(2) If you are using explosives, the following:
(i) Type of explosives;
(ii) Number and sizes of charges;
(iii) Whether you are using single shot or multiple shots;
(iv) If multiple shots, the sequence and timing of detonations;
(v) Whether you are using a bulk or shaped charge;
(vi) Depth of detonation below the mud line; and
(vii) Whether you are placing the explosives inside or outside of the pilings;
(3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and marine mammals, a description of the proposed detection method; and
(4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations.
(g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform.
(h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site.
(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take to minimize such impacts.
(j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine life.
§ 250.1728 To what depth must I remove a platform or other facility?
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(a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line.
(b) The Regional Supervisor may approve an alternate removal depth if:
(1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
§ 250.1729 After I remove a platform or other facility, what information must I submit?
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Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional Supervisor that includes the following:
(a) A summary of the removal operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the platform or other facility were consistent with those set forth in the approved removal application.
§ 250.1730 When might MMS approve partial structure removal or toppling in place?
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The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by approving partial structure removal or toppling in place for conversion to an artificial reef or other use if you meet the following conditions:
(a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and (continued)