129 Subpart F—Oil and Gas Well- Workover Operations

Safety & Environmental Enforcement, Interior § 250.601

(n) Date of diagnostic test; gional Supervisor, Field Operations, (o) Well schematic; within 14 days of completion of the di- (p) Water depth; agnostic test required under § 250.522(e). (q) Volumes and types of fluid bled [76 FR 64462, Oct. 18, 2011. Redesignated at 77 from each casing or riser evaluated; FR 50894, Aug. 22, 2012] (r) Type of diagnostic test performed: (1) Bleed down/buildup test; § 250.531 When does my casing pres- (2) Shut-in the well and monitor the sure request approval become in- pressure drop test; valid? (3) Constant production rate and de- A casing pressure request becomes crease the annular pressure test; invalid when: (4) Constant production rate and in- (a) The casing or riser pressure in- crease the annular pressure test; creases by 200 psig over the approved (5) Change the production rate and casing pressure request pressure; monitor the casing pressure test; and (b) The approved term ends; (6) Casing pressure and tubing pres- (c) The well is worked-over, side- sure history plot; tracked, redrilled, recompleted, or acid (s) The casing diagnostic test data stimulated; for all casing exceeding 100 psig; (d) A different casing or riser on the (t) Associated shoe strengths for cas- same well requires a casing pressure re- ing shoes exposed to annular fluids; quest; or (u) Concentration of any H S that 2 (e) A well has more than one casing may be present; operating under a casing pressure re- (v) Whether the structure on which quest and one of the casing pressure re- the well is located is manned or un- manned; quests become invalid, then all casing (w) Additional comments; and pressure requests for that well become (x) Request date. invalid. [76 FR 64462, Oct. 18, 2011. Redesignated at 77 [76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012] FR 50894, Aug. 22, 2012] § 250.529 What are the terms of my Subpart F—Oil and Gas Well- casing pressure request? Workover Operations Casing pressure requests are approved by the Regional Supervisor, § 250.600 General requirements. Field Operations, for a term to be de- Well-workover operations shall be termined by the Regional Supervisor conducted in a manner to protect on a case-by-case basis. The Regional against harm or damage to life (includ- Supervisor may impose additional re- ing fish and other aquatic life), prop- strictions or requirements to allow erty, natural resources of the Outer continued operation of the well. Continental Shelf (OCS) including any [76 FR 64462, Oct. 18, 2011. Redesignated at 77 mineral deposits (in areas leased and FR 50894, Aug. 22, 2012] not leased), the National security or defense, or the marine, coastal, or § 250.530 What if my casing pressure human environment. request is denied? (a) If your casing pressure request is § 250.601 Definitions. denied, then the operating company When used in this subpart, the fol- must submit plans for corrective ac- lowing terms shall have the meanings tion to the respective District Manager given below: within 30 days of receiving the denial. Expected surface pressure means the The District Manager will establish a highest pressure predicted to be ex- specific time period in which this cor- erted upon the surface of a well. In cal- rective action will be taken. You must culating expected surface pressure, you notify the respective District Manager must consider reservoir pressure as within 30 days after completion of your well as applied surface pressure. corrected action. Routine operations mean any of the (b) You must submit the casing diag- following operations conducted on a nostic test data to the appropriate Re- well with the tree installed:

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(a) Cutting paraffin; § 250.603 Emergency shutdown system. (b) Removing and setting pump- When well-workover operations are through-type tubing plugs, gas-lift valves, and subsurface safety valves conducted on a well with the tree re- which can be removed by wireline oper- moved, an emergency shutdown system ations; (ESD) manually controlled station (c) Bailing sand; shall be installed near the driller’s con- (d) Pressure surveys; sole or well-servicing unit operator’s (e) Swabbing; work station, except when there is no (f) Scale or corrosion treatment; other hydrocarbon-producing well or (g) Caliper and gauge surveys; other hydrocarbon flow on the plat- (h) Corrosion inhibitor treatment; form. (i) Removing or replacing subsurface pumps; § 250.604 Hydrogen sulfide. (j) Through-tubing logging When a well-workover operation is (diagnostics); conducted in zones known to contain (k) Wireline fishing; and hydrogen sulfide (H S) or in zones (l) Setting and retrieving other sub- 2 where the presence of H S is unknown surface flow-control devices. 2 (as defined in § 250.490 of this part), the Workover operations mean the work conducted on wells after the initial lessee shall take appropriate pre- completion for the purpose of main- cautions to protect life and property on taining or restoring the productivity of the platform or rig, including but not a well. limited to operations such as blowing the well down, dismantling wellhead § 250.602 Equipment movement. equipment and flow lines, circulating The movement of well-workover rigs the well, swabbing, and pulling tubing, and related equipment on and off a pumps and packers. The lessee shall platform or from well to well on the comply with the requirements in same platform, including rigging up § 250.490 of this part as well as the ap- and rigging down, shall be conducted in propriate requirements of this subpart. a safe manner. All wells in the same well-bay which are capable of pro- § 250.605 Subsea workovers. ducing hydrocarbons shall be shut in No subsea well-workover operation below the surface with a pump- including routine operations shall be through-type tubing plug and at the commenced until the lessee obtains surface with a closed master valve written approval from the District prior to moving well-workover rigs and Manager in accordance with § 250.613 of related equipment unless otherwise ap- this part. That approval shall be based proved by the District Manager. A upon a case-by-case determination that closed surface-controlled subsurface the proposed equipment and procedures safety valve of the pump-through-type will maintain adequate control of the may be used in lieu of the pump- through-type tubing plug provided that well and permit continued safe produc- the surface control has been locked out tion operations. of operation. The well to which a well- § 250.606 Crew instructions. workover rig or related equipment is to be moved shall also be equipped with a Prior to engaging in well-workover back-pressure valve prior to removing operations, crew members shall be in- the tree and installing and testing the structed in the safety requirements of blowout-preventer (BOP) system. The the operations to be performed, pos- well from which a well-workover rig or sible hazards to be encountered, and related equipment is to be moved shall general safety considerations to pro- also be equipped with a back pressure tect personnel, equipment, and the en- valve prior to removing the BOP sys- vironment. Date and time of safety tem and installing the tree. Coiled tub- meetings shall be recorded and avail- ing units, snubbing units, or wireline able at the facility for review by a units may be moved onto a platform BSEE representative. without shutting in wells.

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§§ 250.607–250.608 [Reserved] well-workover rules have been established, well-workover operations in the § 250.609 Well-workover structures on field shall be conducted in accordance fixed platforms. with such rules and other requirements Derricks, masts, substructures, and of this subpart. Field well-workover related equipment shall be selected, de- rules may be amended or canceled for signed, installed, used, and maintained cause at any time upon the initiative so as to be adequate for the potential of the District Manager or upon the re- loads and conditions of loading that quest of a lessee. may be encountered during the operations proposed. Prior to moving a § 250.613 Approval and reporting for well-workover rig or well-servicing well-workover operations. equipment onto a platform, the lessee (a) No well-workover operation ex- shall determine the structural capa- cept routine ones, as defined in § 250.601 bility of the platform to safely support of this part, shall begin until the lessee the equipment and proposed oper- receives written approval from the Dis- ations, taking into consideration the trict Manager. Approval for these oper- corrosion protection, age of the plat- ations must be requested on Form form, and previous stresses to the plat- BSEE–0124, Application for Permit to form. Modify. (b) You must submit the following § 250.610 Diesel engine air intakes. with Form BSEE–0124: No later than May 31, 1989, diesel en- (1) A brief description of the well- gine air intakes shall be equipped with workover procedures to be followed, a a device to shut down the diesel engine statement of the expected surface pres- in the event of runaway. Diesel engines sure, and type and weight of workover which are continuously attended shall fluids; be equipped with either remote oper- (2) When changes in existing sub- ated manual or automatic shutdown surface equipment are proposed, a sche- devices. Diesel engines which are not matic drawing of the well showing the continuously attended shall be zone proposed for workover and the equipped with automatic shutdown de- workover equipment to be used; vices. (3) All information required in § 250.615. § 250.611 Traveling-block safety de- (4) Where the well-workover is in a vice. zone known to contain H2S or a zone After May 31, 1989, all units being where the presence of H2S is unknown, used for well-workover operations information pursuant to § 250.490 of this which have both a traveling block and part; and a crown block shall be equipped with a (5) Payment of the service fee listed safety device which is designed to pre- in § 250.125. vent the traveling block from striking (c) The following additional informa- the crown block. The device shall be tion shall be submitted with Form checked for proper operation weekly BSEE–0124 if completing to a new zone and after each drill-line slipping oper- is proposed: ation. The results of the operational (1) Reason for abandonment of check shall be entered in the oper- present producing zone including sup- ations log. portive well test data, and (2) A statement of anticipated or § 250.612 Field well-workover rules. known pressure data for the new zone. When geological and engineering in- (d) Within 30 days after completing formation available in a field enables the well-workover operation, except the District Manager to determine spe- routine operations, Form BSEE–0124, cific operating requirements, field Application for Permit to Modify, shall well-workover rules may be established be submitted to the District Manager, on the District Manager’s initiative or showing the work as performed. In the in response to a request from a lessee. case of a well-workover operation re- Such rules may modify the specific re- sulting in the initial recompletion of a quirements of this subpart. After field well into a new zone, a Form BSEE–

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0125, End of Operations Report, shall be an underbalanced state, you must ob- submitted to the District Manager and tain approval from the BSEE District shall include a new schematic of the Manager. To obtain approval, you must tubing subsurface equipment if any submit with your APM your reasons subsurface equipment has been for displacing the kill-weight fluid and changed. provide detailed step-by-step written [76 FR 64462, Oct. 18, 2011, as amended at 77 procedures describing how you will FR 50895, Aug. 22, 2012] safely displace these fluids. The step- by-step displacement procedures must § 250.614 Well-control fluids, equip- address the following: ment, and operations. (1) Number and type of independent The following requirements apply barriers, as described in § 250.420(b)(3), during all well-workover operations that are in place for each flow path with the tree removed: that requires such barriers, (a) Well-control fluids, equipment, (2) Tests you will conduct to ensure and operations shall be designed, uti- integrity of independent barriers, lized, maintained, and/or tested as nec- (3) BOP procedures you will use while essary to control the well in foresee- displacing kill weight fluids, and able conditions and circumstances, in- (4) Procedures you will use to mon- cluding subfreezing conditions. The itor the volumes and rates of fluids en- well shall be continuously monitored during well-workover operations and tering and leaving the wellbore. shall not be left unattended at anytime [76 FR 64462, Oct. 18, 2011, as amended at 77 unless the well is shut in and secured. FR 50895, Aug. 22, 2012] (b) When coming out of the hole with drill pipe or a workover string, the an- § 250.615 What BOP information must nulus shall be filled with well-control I submit? fluid before the change in such fluid For well-workover operations, your level decreases the hydrostatic pres- APM must include the following BOP sure 75 pounds per square inch (psi) or descriptions: every five stands of drill pipe or (a) A description of the BOP system workover string, whichever gives a and system components, including lower decrease in hydrostatic pressure. pressure ratings of BOP equipment and The number of stands of drill pipe or proposed BOP test pressures; workover string and drill collars that (b) A schematic drawing of the BOP may be pulled prior to filling the hole system that shows the inside diameter and the equivalent well-control fluid of the BOP stack, number and type of volume shall be calculated and posted preventers, all control systems and near the operator’s station. A mechan- pods, location of choke and kill lines, ical, volumetric, or electronic device and associated valves; for measuring the amount of well-control fluid required to fill the hold shall (c) Independent third-party be utilized. verification and supporting docu- (c) The following well-control-fluid mentation that show the blind-shear equipment shall be installed, main- rams installed in the BOP stack are ca- tained, and utilized: pable of shearing any drill pipe (includ- (1) A fill-up line above the uppermost ing workstring and tubing) in the hole BOP; under maximum anticipated surface (2) A well-control, fluid-volume pressure. The documentation must in- measuring device for determining fluid clude actual shearing and subsequent volumes when filling the hole on trips; pressure integrity test results for the and most rigid pipe to be used and calcula- (3) A recording mud-pit-level indi- tions of shearing capacity of all pipe to cator to determine mud-pit-volume be used in the well, including correc- gains and losses. This indicator shall tion for under maximum anticipated include both a visual and an audible surface pressure; warning device. (d) When you use a subsea BOP stack, (d) Before you displace kill-weight independent third-party verification fluid from the wellbore and/or riser to that shows:

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(1) The BOP stack is designed for the mitted to BSEE. Prior to any shearing specific equipment on the rig and for ram tests or inspections, you must no- the specific well design; tify the BSEE District Manager at (2) The BOP stack has not been com- least 72 hours in advance. promised or damaged from previous service; [77 FR 50895, Aug. 22, 2012] (3) The BOP stack will operate in the § 250.616 Blowout prevention equip- conditions in which it will be used; and ment. (e) The qualifications of the independent third-party referenced in para- (a) The BOP system, system compo- graphs (c) and (d) of this section: nents and related well-control equip- (1) The independent third-party in ment shall be designed, used, main- this section must be a technical classi- tained, and tested in a manner nec- fication society, or a licensed profes- essary to assure well control in foresee- sional engineering firm, or a registered able conditions and circumstances, in- professional engineer capable of pro- cluding subfreezing conditions. The viding the verifications required under working pressure rating of the BOP this part. system and system components shall (2) You must: exceed the expected surface pressure to (i) Include evidence that the reg- which they may be subjected. If the ex- istered professional engineer, or a tech- pected surface pressure exceeds the nical classification society, or engi- rated working pressure of the annular neering firm you are using or its em- preventer, the lessee shall submit with ployees hold appropriate licenses to Form BSEE–0124, requesting approval perform the verification in the appro- of the well-workover operation, a well- priate jurisdiction, and evidence to control procedure that indicates how demonstrate that the individual, soci- the annular preventer will be utilized, ety, or firm has the expertise and expe- and the pressure limitations that will rience necessary to perform the re- be applied during each mode of pres- quired verifications. sure control. (ii) Ensure that an official represent- (b) The minimum BOP system for ative of BSEE will have access to the well-workover operations with the tree location to witness any testing or in- removed must meet the appropriate spections, and verify information sub- standards from the following table:

When . . . The minimum BOP stack must include . . .

(1) The expected pressure is less than 5,000 psi, Three BOPs consisting of an annular, one set of pipe rams, and one set of blind-shear rams. (2) The expected pressure is 5,000 psi or greater or you use Four BOPs consisting of an annular, two sets of pipe rams, multiple tubing strings, and one set of blind-shear rams. (3) You handle multiple tubing strings simultaneously, Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe rams, and one set of blind-shear rams. (4) You use a tapered drill string, At least one set of pipe rams that are capable of sealing around each size of drill string. If the expected pressure is greater than 5,000 psi, then you must have at least two sets of pipe rams that are capable of sealing around the larger size drill string. You may substitute one set of variable bore rams for two sets of pipe rams. (5) You use a subsea BOP stack, The requirements in § 250.442(a) of this part.

(c) The BOP systems for well- out assistance from a charging system. workover operations with the tree re- Accumulator regulators supplied by rig moved must be equipped with the fol- air and without a secondary source of lowing: pneumatic supply, must be equipped (1) A hydraulic-actuating system with manual overrides, or alternately, that provides sufficient accumulator other devices provided to ensure capa- capacity to supply 1.5 times the volume bility of hydraulic operations if rig air necessary to close all BOP equipment is lost; units with a minimum pressure of 200 (2) A secondary power source, inde- psi above the precharge pressure with- pendent from the primary power

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source, with sufficient capacity to (d) The minimum BOP-system com- close all BOP system components and ponents for well-workover operations hold them closed; with the tree in place and performed (3) Locking devices for the pipe-ram through the wellhead inside of conven- preventers; tional tubing using small-diameter (4) At least one remote BOP-control 3 1 jointed pipe (usually ⁄4 inch to 1 ⁄4 station and one BOP-control station on inch) as a work string, i.e., small-tub- the rig floor; and ing operations, shall include the fol- (5) A choke line and a kill line each lowing: equipped with two full opening valves and a choke manifold. At least one of (1) Two sets of pipe rams, and the valves on the choke-line shall be (2) One set of blind rams. remotely controlled. At least one of (e) The subsea BOP system for well- the valves on the kill line shall be re- workover operations must meet the remotely controlled, except that a check quirements in § 250.442 of this part. valve on the kill line in lieu of the re- (f) For coiled tubing operations with motely controlled valve may be in- the production tree in place, you must stalled provided two readily accessible meet the following minimum require- manual valves are in place and the ments for the BOP system: check valve is placed between the man- (1) BOP system components must be ual valves and the pump. This equip- in the following order from the top ment shall have a pressure rating at down: least equivalent to the ram preventers.

BOP system when expected BOP system when expected surface pressures are less than or equal surface pressures are greater than 3,500 BOP system for wells with returns taken to 3,500 psi psi through an outlet on the BOP stack

Stripper or annular-type well control com- Stripper or annular-type well control Stripper or annular-type well control ponent. component. component. Hydraulically-operated blind rams ...... Hydraulically-operated blind rams ...... Hydraulically-operated blind rams Hydraulically-operated shear rams ...... Hydraulically-operated shear rams ...... Hydraulically-operated shear rams. Kill line inlet ...... Kill line inlet ...... Kill line inlet. Hydraulically-operated two-way slip rams Hydraulically-operated two-way slip rams Hydraulically-operated two-way slip rams. Hydraulically-operated pipe rams. Hydraulically-operated pipe rams ...... Hydraulically-operated pipe rams ...... A flow tee or cross. Hydraulically-operated blind-shear rams. Hydraulically-operated pipe rams. These rams should be located as Hydraulically-operated blind-shear rams close to the tree as practical. on wells with surface pressures >3,500 psi. As an option, the pipe rams can be placed below the blind- shear rams. The blind-shear rams should be located as close to the tree as practical.

(2) You may use a set of hydrau- for Permit to Modify and have it ap- lically-operated combination rams for proved by the District Manager. the blind rams and shear rams. (5) You must have a kill line and a (3) You may use a set of hydrau- separate choke line. You must equip lically-operated combination rams for each line with two full-opening valves the hydraulic two-way slip rams and and at least one of the valves must be the hydraulically-operated pipe rams. remotely controlled. You may use a (4) You must attach a dual check manual valve instead of the remotely valve assembly to the coiled tubing controlled valve on the kill line if you connector at the downhole end of the install a check valve between the two full-opening manual valves and the coiled tubing string for all coiled tub- pump or manifold. The valves must ing well-workover operations. If you have a working pressure rating equal plan to conduct operations without to or greater than the working pres- downhole check valves, you must de- sure rating of the connection to which scribe alternate procedures and equip- they are attached, and you must in- ment in Form BSEE–0124, Application stall them between the well control

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stack and the choke or kill line. For pressure test for each component. You operations with expected surface pres- must conduct the low-pressure test be- sures greater than 3,500 psi, the kill fore the high-pressure test. For pur- line must be connected to a pump or poses of this section, BOP system com- manifold. You must not use the kill ponents include ram-type BOP’s, re- line inlet on the BOP stack for taking lated control equipment, choke and fluid returns from the wellbore. kill lines, and valves, manifolds, strip- (6) You must have a hydraulic-actu- pers, and safety valves. Surface BOP ating system that provides sufficient systems must be pressure tested with accumulator capacity to close-open- water. close each component in the BOP (1) Low pressure tests. All BOP system stack. This cycle must be completed with at least 200 psi above the pre- components must be successfully test- charge pressure, without assistance ed to a low pressure between 200 and 300 from a charging system. psi. Any initial pressure equal to or (7) All connections used in the sur- greater than 300 psi must be bled back face BOP system from the tree to the to a pressure between 200 and 300 psi uppermost required ram must be before starting the test. If the initial flanged, including the connections be- pressure exceeds 500 psi, you must tween the well control stack and the bleed back to zero before starting the first full-opening valve on the choke test. line and the kill line. (2) High pressure tests. All BOP system (g) The minimum BOP-system com- components must be successfully test- ponents for well-workover operations ed to the rated working pressure of the with the tree in place and performed by BOP equipment, or as otherwise ap- moving tubing or drill pipe in or out of proved by the District Manager. The a well under pressure utilizing equip- annular-type BOP must be successfully ment specifically designed for that pur- tested at 70 percent of its rated work- pose, i.e., snubbing operations, shall in- ing pressure or as otherwise approved clude the following: by the District Manager. (1) One set of pipe rams hydraulically (3) Other testing requirements. Variable operated, and bore pipe rams must be pressure tested (2) Two sets of stripper-type pipe against the largest and smallest sizes rams hydraulically operated with spac- of tubulars in use (jointed pipe, seam- er spool. less pipe) in the well. (h) An inside BOP or a spring-loaded, back-pressure safety valve and an es- (b) Times. The BOP systems shall be sentially full-opening, work-string tested at the following times: safety valve in the open position shall (1) When installed; be maintained on the rig floor at all (2) At least every 7 days, alternating times during well-workover operations between control stations and at stag- when the tree is removed or during gered intervals to allow each crew to well-workover operations with the tree operate the equipment. If either con- installed and using small tubing as the trol system is not functional, further work string. A wrench to fit the work- operations shall be suspended until the string safety valve shall be readily nonfunctional, system is operable. The available. Proper connections shall be test every 7 days is not required for readily available for inserting valves in blind or blind-shear rams. The blind or the work string. The full-opening safe- blind-shear rams shall be tested at ty valve is not required for coiled tub- least once every 30 days during oper- ing or snubbing operations. ation. A longer period between blowout [76 FR 64462, Oct. 18, 2011. Redesignated at 77 preventer tests is allowed when there is FR 50895, Aug. 22, 2012] a stuck pipe or pressure-control operation and remedial efforts are being § 250.617 Blowout preventer system performed. The tests shall be con- testing, records, and drills. ducted as soon as possible and before (a) BOP pressure tests. When you pres- normal operations resume. The reason sure test the BOP system you must for postponing testing shall be entered conduct a low-pressure test and a high- into the operations log.

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(3) Following repairs that require dis- (2) The control station used during connecting a pressure seal in the as- the test shall be identified in the oper- sembly, the affected seal will be pres- ations log. For a subsea system, the sure tested. pod used during the test shall be iden- (c) Drills. All personnel engaged in tified in the operations log. well-workover operations shall partici- (3) Any problems or irregularities ob- pate in a weekly BOP drill to famil- served during BOP and auxiliary equip- iarize crew members with appropriate ment testing and any actions taken to safety measures. remedy such problems or irregularities (d) Stump tests. You may conduct a shall be noted in the operations log. stump test for the BOP system on loca- (4) Documentation required to be en- tion. A plan describing the stump test tered in the operation log may instead procedures must be included in your be referenced in the operations log. All Form BSEE–0124, Application for Per- records including pressure charts, oper- mit to Modify, and must be approved ations log, and referenced documents by the District Manager. pertaining to BOP tests, actuations, (e) Coiled tubing tests. You must test and inspections, shall be available for the coiled tubing connector to a low BSEE review at the facility for the du- pressure of 200 to 300 psi, followed by a ration of well-workover activity. Fol- high pressure test to the rated working lowing completion of the well- workover activity, all such records pressure of the connector or the ex- shall be retained for a period of 2 years pected surface pressure, whichever is at the facility, at the lessee’s filed of- less. You must successfully pressure fice nearest the OCS facility, or at an- test the dual check valves to the rated other location conveniently available working pressure of the connector, the to the District Manager. rated working pressure of the dual (h) Stump test a subsea BOP system check valve, expected surface pressure, before installation. You must use or the collapse pressure of the coiled water to conduct this test. You may tubing, whichever is less. use drilling or completion fluids to (f) Recordings. You must record test conduct subsequent tests of a subsea pressures during BOP and coiled tubing BOP system. You must perform the ini- tests on a pressure chart, or with a dig- tial subsea BOP test on the seafloor ital recorder, unless otherwise ap- within 30 days of the stump test. You proved by the District Manager. The must: test interval for each BOP system com- (1) Test all ROV intervention func- ponent must be 5 minutes, except for tions on your subsea BOP stack during coiled tubing operations, which must the stump test. Each ROV must be include a 10 minute high-pressure test fully compatible with the BOP stack for the coiled tubing string. Your rep- ROV intervention panels. You must resentative at the facility must certify also test and verify closure of at least that the charts are correct. one set of rams during the initial test (g) Operations log. The time, date, and on the seafloor through an ROV hot results of all pressure tests, actuations, stab. You must submit test procedures, inspections, and crew drills of the BOP including how you will test each ROV system, system components, and ma- function, with your APM for BSEE Dis- rine risers shall be recorded in the op- trict Manager approval. You must: erations log. The BOP tests shall be (i) Ensure that the ROV hot stabs are documented in accordance with the fol- function tested and are capable of actu- lowing: ating, at a minimum, one set of pipe (1) The documentation shall indicate rams, one set of blind-shear rams, and the sequential order of BOP and auxil- unlatching the LMRP; iary equipment testing and the pres- (ii) Notify the appropriate BSEE Dis- sure and duration of each test. As an trict Manager a minimum of 72 hours alternate, the documentation in the prior to the stump test and initial test operations log may reference a BOP on the seafloor; test plan that contains the required in- (iii) Document all your test results formation and is retained on file at the and make them available to BSEE facility. upon request; and

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(2) Function test autoshear and conditions permit. You may use tele- deadman systems on your subsea BOP vision cameras to inspect subsea equip- stack during the stump test. You must ment. The BSEE District Manager may also test the deadman system and approve alternate methods and fre- verify closure of at least one set of quencies to inspect a marine riser. blind-shear rams during the initial test (b) BOP maintenance. You must main- on the seafloor. When you conduct the tain your BOP system to ensure that initial deadman system test on the the equipment functions properly. The seafloor you must ensure the well is se- BOP maintenance must meet or exceed cure and, if hydrocarbons have been the provisions of Sections 17.11 and present, appropriate barriers are in 18.11, Maintenance; and Sections 17.12 place to isolate hydrocarbons from the and 18.12, Quality Management, de- wellhead. You must also have an ROV scribed in API RP 53, Recommended on bottom during the test. You must: Practices for Blowout Prevention (i) Submit test procedures with your Equipment Systems for Drilling Wells APM for BSEE District Manager ap- (incorporated by reference as specified proval. The procedures for these func- in § 250.198). You must document how tion tests must include documentation you met or exceeded the provisions of of the controls and circuitry of the sys- Sections 17.11 and 18.11, Maintenance; tem utilized during each test. The pro- and Sections 17.12 and 18.12, Quality cedure must also describe how the ROV Management, described in API RP 53, will be utilized during this operation. the procedures used, record the results, (ii) Document the results of each test and make the records available to and make them available to BSEE BSEE upon request. You must main- upon request. tain your records on the rig for 2 years [76 FR 64462, Oct. 18, 2011. Redesignated and from the date the records are created, amended at 77 FR 50895, 50896, Aug. 22, 2012] or for a longer period if directed by BSEE. § 250.618 What are my BOP inspection and maintenance requirements? [77 FR 50896, Aug. 22, 2012] (a) BOP inspections. (1) You must in- § 250.619 Tubing and wellhead equip- spect your BOP system to ensure that ment. the equipment functions properly. The BOP inspections must meet or exceed The lessee shall comply with the fol- the provisions of Sections 17.10 and lowing requirements during well- 18.10, Inspections, described in API RP workover operations with the tree re- 53, Recommended Practices for Blow- moved: out Prevention Equipment Systems for (a) No tubing string shall be placed in Drilling Wells (incorporated by ref- service or continue to be used unless erence as specified in § 250.198). You such tubing string has the necessary must document how you met or exceed- strength and pressure integrity and is ed the provisions of Sections 17.10 and otherwise suitable for its intended use. 18.10 described in API RP 53, the proce- (b) In the event of prolonged oper- dures used, record the results, and ations such as milling, fishing, jarring, make the records available to BSEE or washing over that could damage the upon request. You must maintain your casing, the casing shall be pressure records on the rig for 2 years from the tested, calipered, or otherwise evalu- date the records are created, or for a ated every 30 days and the results sub- longer period if directed by BSEE. mitted to the District Manager. (2) You must visually inspect your (c) When reinstalling the tree, you surface BOP system on a daily basis. must: You must visually inspect your subsea (1) Equip wells to monitor for casing BOP system and marine riser at least pressure according to the following once every 3 days if weather and sea chart:

If you have . . . you must equip . . . so you can monitor . . .

(i) fixed platform wells, the wellhead, all annuli (A, B, C, D, etc., annuli). (ii) subsea wells, the tubing head, the production casing annulus (A annulus).

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If you have . . . you must equip . . . so you can monitor . . .

(iii) hybrid* wells, the surface wellhead, all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the production casing riser above the mudline are pressure isolated from each other, provisions must be made to monitor the production casing below the mudline for casing pressure. * Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a surface tubing hanger, and a surface christmas tree.

(2) Follow the casing pressure man- Subpart H—Oil and Gas agement requirements in subpart E of Production Safety Systems this part. (d) Wellhead, tree, and related equip- § 250.800 General requirements. ment shall have a pressure rating (a) Production safety equipment greater than the shut-in tubing pres- shall be designed, installed, used, sure and shall be designed, installed, maintained, and tested in a manner to used, maintained, and tested so as to assure the safety and protection of the achieve and maintain pressure control. human, marine, and coastal environ- The tree shall be equipped with a min- ments. Production safety systems oper- imum of one master valve and one sur- ated in subfreezing climates shall uti- face safety valve in the vertical run of lize equipment and procedures selected the tree when it is reinstalled. with consideration of floating ice, (e) Subsurface safety equipment shall icing, and other extreme environ- be installed, maintained, and tested in mental conditions that may occur in compliance with § 250.801 of this part. the area. Production shall not com- mence until the production safety sys- [76 FR 64462, Oct. 18, 2011. Redesignated at 77 tem has been approved and a FR 50895, Aug. 22, 2012] preproduction inspection has been re- § 250.620 Wireline operations. quested by the lessee. (b) For all new floating production The lessee shall comply with the fol- systems (FPSs) (e.g., column-sta- lowing requirements during routine, as bilized-units (CSUs); floating produc- defined in § 250.601 of this part, and tion, storage and offloading facilities nonroutine wireline workover oper- (FPSOs); tension-leg platforms (TLPs); ations: spars, etc.), you must do all of the fol- (a) Wireline operations shall be con- lowing: ducted so as to minimize leakage of (1) Comply with API RP 14J (as in- well fluids. Any leakage that does corporated by reference in 30 CFR occur shall be contained to prevent pol- 250.198); lution. (2) Meet the drilling and production (b) All wireline perforating oper- riser standards of API RP 2RD (as in- ations and all other wireline operations corporated by reference in 30 CFR where communication exists between 250.198); the completed hydrocarbon-bearing (3) Design all stationkeeping systems zone(s) and the wellbore shall use a lu- for floating facilities to meet the bricator assembly containing at least standards of API RP 2SK (as incor- one wireline valve. porated by reference in 30 CFR 250.198), (c) When the lubricator is initially as well as relevant U.S. Coast Guard installed on the well, it shall be suc- regulations; and cessfully pressure tested to the ex- (4) Design stationkeeping systems for pected shut-in surface pressure. floating facilities to meet structural requirements in subpart I, §§ 250.900 [76 FR 64462, Oct. 18, 2011. Redesignated at 77 through 250.921 of this part. FR 50895, Aug. 22, 2012] § 250.801 Subsurface safety devices. Subpart G [Reserved] (a) General. All tubing installations open to hydrocarbon-bearing zones

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