eCFR 30 CFR 250, Subpart F

eCFR — Code of Federal Regulations
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ELECTRONIC CODE OF FEDERAL REGULATIONS
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Title 30: Mineral Resources

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PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

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Subpart F—Oil and Gas Well-Workover Operations

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§250.600   General requirements.
§250.601   Definitions.
§250.602   Equipment movement.
§250.603   Emergency shutdown system.
§250.604   Hydrogen sulfide.
§250.605   Subsea workovers.
§250.606   Crew instructions.
§§250.607-250.608   [Reserved]
§250.609   Well-workover structures on fixed platforms.
§250.610   Diesel engine air intakes.
§250.611   Traveling-block safety device.
§250.612   Field well-workover rules.
§250.613   Approval and reporting for well-workover operations.
§250.614   Well-control fluids, equipment, and operations.
§250.615   What BOP information must I submit?
§250.616   Blowout prevention equipment.
§250.617   Blowout preventer system testing, records, and drills.
§250.618   What are my BOP inspection and maintenance requirements?
§250.619   Tubing and wellhead equipment.
§250.620   Wireline operations.

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§250.600   General requirements.

Purchase individual CFR titles from
the U.S. Government Online Bookstore.

Find issues of the CFR (including issues
prior to 1996) at a local Federal
depository library.

Link to an amendment published at 81 FR 26021, April 29, 2016.

Well-workover operations shall be conducted in a manner to protect against harm or damage to life (including fish and
other aquatic life), property, natural resources of the Outer Continental Shelf (OCS) including any mineral deposits (in
areas leased and not leased), the National security or defense, or the marine, coastal, or human environment.

[A1]
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§250.601   Definitions.
When used in this subpart, the following terms shall have the meanings given below:
Expected surface pressure means the highest pressure predicted to be exerted upon the surface of a well. In
calculating expected surface pressure, you must consider reservoir pressure as well as applied surface pressure.
Routine operations mean any of the following operations conducted on a well with the tree installed:

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(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves which can be
removed by wireline operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
Workover operations mean the work conducted on wells after the initial completion for the purpose of maintaining or
restoring the productivity of a well.
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§250.602   Equipment movement.
Link to an amendment published at 81 FR 26021, April 29, 2016.

The movement of well-workover rigs and related equipment on and off a platform or from well to well on the same
platform, including rigging up and rigging down, shall be conducted in a safe manner. All wells in the same well-bay which
are capable of producing hydrocarbons shall be shut in below the surface with a pump-through-type tubing plug and at the
surface with a closed master valve prior to moving well-workover rigs and related equipment unless otherwise approved
by the District Manager. A closed surface-controlled subsurface safety valve of the pump-through-type may be used in
lieu of the pump-through-type tubing plug provided that the surface control has been locked out of operation. The well to
which a well-workover rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to
removing the tree and installing and testing the blowout-preventer (BOP) system. The well from which a well-workover rig
or related equipment is to be moved shall also be equipped with a back pressure valve prior to removing the BOP system
and installing the tree. Coiled tubing units, snubbing units, or wireline units may be moved onto a platform without shutting
in wells.
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§250.603   Emergency shutdown system.
When well-workover operations are conducted on a well with the tree removed, an emergency shutdown system
(ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station,
except when there is no other hydrocarbon-producing well or other hydrocarbon flow on the platform.
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§250.604   Hydrogen sulfide.
When a well-workover operation is conducted in zones known to contain hydrogen sulfide (H2S) or in zones where the
presence of H2S is unknown (as defined in §250.490 of this part), the lessee shall take appropriate precautions to protect
life and property on the platform or rig, including but not limited to operations such as blowing the well down, dismantling
wellhead equipment and flow lines, circulating the well, swabbing, and pulling tubing, pumps and packers. The lessee
shall comply with the requirements in §250.490 of this part as well as the appropriate requirements of this subpart.
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§250.605   Subsea workovers.
No subsea well-workover operation including routine operations shall be commenced until the lessee obtains written
approval from the District Manager in accordance with §250.613 of this part. That approval shall be based upon a caseby-case determination that the proposed equipment and procedures will maintain adequate control of the well and permit
continued safe production operations.

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§250.606   Crew instructions.
Link to an amendment published at 81 FR 26021, April 29, 2016.

Prior to engaging in well-workover operations, crew members shall be instructed in the safety requirements of the
operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel,
equipment, and the environment. Date and time of safety meetings shall be recorded and available at the facility for
review by a BSEE representative.
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§§250.607-250.608   [Reserved]
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§250.609   Well-workover structures on fixed platforms.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so
as to be adequate for the potential loads and conditions of loading that may be encountered during the operations
proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lessee shall determine the
structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the
corrosion protection, age of the platform, and previous stresses to the platform.
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§250.610   Diesel engine air intakes.
No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shut down the diesel engine
in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated
manual or automatic shutdown devices. Diesel engines which are not continuously attended shall be equipped with
automatic shutdown devices.
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§250.611   Traveling-block safety device.
After May 31, 1989, all units being used for well-workover operations which have both a traveling block and a crown
block shall be equipped with a safety device which is designed to prevent the traveling block from striking the crown block.
The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the
operational check shall be entered in the operations log.
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§250.612   Field well-workover rules.
When geological and engineering information available in a field enables the District Manager to determine specific
operating requirements, field well-workover rules may be established on the District Manager's initiative or in response to
a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-workover rules
have been established, well-workover operations in the field shall be conducted in accordance with such rules and other
requirements of this subpart. Field well-workover rules may be amended or canceled for cause at any time upon the
initiative of the District Manager or upon the request of a lessee.
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§250.613   Approval and reporting for well-workover operations.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) No well-workover operation except routine ones, as defined in §250.601 of this part, shall begin until the lessee
receives written approval from the District Manager. Approval for these operations must be requested on Form BSEE0124, Application for Permit to Modify.
(b) You must submit the following with Form BSEE-0124:

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(1) A brief description of the well-workover procedures to be followed, a statement of the expected surface pressure,
and type and weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the zone
proposed for workover and the workover equipment to be used;
(3) All information required in §250.615.
(4) Where the well-workover is in a zone known to contain H2S or a zone where the presence of H2S is unknown,
information pursuant to §250.490 of this part; and
(5) Payment of the service fee listed in §250.125.
(c) The following additional information shall be submitted with Form BSEE-0124 if completing to a new zone is
proposed:
(1) Reason for abandonment of present producing zone including supportive well test data, and
(2) A statement of anticipated or known pressure data for the new zone.
(d) Within 30 days after completing the well-workover operation, except routine operations, Form BSEE-0124,
Application for Permit to Modify, shall be submitted to the District Manager, showing the work as performed. In the case of
a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form BSEE-0125, End of
Operations Report, shall be submitted to the District Manager and shall include a new schematic of the tubing subsurface
equipment if any subsurface equipment has been changed.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012]
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§250.614   Well-control fluids, equipment, and operations.
Link to an amendment published at 81 FR 26021, April 29, 2016.

The following requirements apply during all well-workover operations with the tree removed:
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary
to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be
continuously monitored during well-workover operations and shall not be left unattended at anytime unless the well is shut
in and secured.
(b) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid
before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five
stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of
drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid
volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for
measuring the amount of well-control fluid required to fill the hold shall be utilized.
(c) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both
a visual and an audible warning device.
(d) Before you displace kill-weight fluid from the wellbore and/or riser to an underbalanced state, you must obtain
approval from the BSEE District Manager. To obtain approval, you must submit with your APM your reasons for displacing
the kill-weight fluid and provide detailed step-by-step written procedures describing how you will safely displace these
fluids. The step-by-step displacement procedures must address the following:
(1) Number and type of independent barriers, as described in §250.420(b)(3), that are in place for each flow path that
requires such barriers,
(2) Tests you will conduct to ensure integrity of independent barriers,
(3) BOP procedures you will use while displacing kill weight fluids, and
(4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50895, Aug. 22, 2012]
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§250.615   What BOP information must I submit?

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For well-workover operations, your APM must include the following BOP descriptions:
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) A description of the BOP system and system components, including pressure ratings of BOP equipment and
proposed BOP test pressures;
(b) A schematic drawing of the BOP system that shows the inside diameter of the BOP stack, number and type of
preventers, all control systems and pods, location of choke and kill lines, and associated valves;
(c) Independent third-party verification and supporting documentation that show the blind-shear rams installed in the
BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole under maximum anticipated
surface pressure. The documentation must include actual shearing and subsequent pressure integrity test results for the
most rigid pipe to be used and calculations of shearing capacity of all pipe to be used in the well, including correction for
under maximum anticipated surface pressure;
(d) When you use a subsea BOP stack, independent third-party verification that shows:
(1) The BOP stack is designed for the specific equipment on the rig and for the specific well design;
(2) The BOP stack has not been compromised or damaged from previous service;
(3) The BOP stack will operate in the conditions in which it will be used; and
(e) The qualifications of the independent third-party referenced in paragraphs (c) and (d) of this section:
(1) The independent third-party in this section must be a technical classification society, or a licensed professional
engineering firm, or a registered professional engineer capable of providing the verifications required under this part.
(2) You must:
(i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm
you are using or its employees hold appropriate licenses to perform the verification in the appropriate jurisdiction, and
evidence to demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the
required verifications.
(ii) Ensure that an official representative of BSEE will have access to the location to witness any testing or
inspections, and verify information submitted to BSEE. Prior to any shearing ram tests or inspections, you must notify the
BSEE District Manager at least 72 hours in advance.
[77 FR 50895, Aug. 22, 2012]
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§250.616   Blowout prevention equipment.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) The BOP system, system components and related well-control equipment shall be designed, used, maintained,
and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including
subfreezing conditions. The working pressure rating of the BOP system and system components shall exceed the
expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working
pressure of the annular preventer, the lessee shall submit with Form BSEE-0124, requesting approval of the wellworkover operation, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure
limitations that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-workover operations with the tree removed must meet the appropriate
standards from the following table:
When .  .  .
(1) The expected
pressure is less than
5,000 psi,
(2) The expected
pressure is 5,000 psi or
greater or you use
multiple tubing strings,
(3) You handle multiple
tubing strings
simultaneously,
(4) You use a tapered
drill string,

(5) You use a subsea
BOP stack,

The minimum BOP stack must include .  .  .
Three BOPs consisting of an annular, one set of pipe rams, and one set of blind-shear rams.

Four BOPs consisting of an annular, two sets of pipe rams, and one set of blind-shear rams.

Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe rams, and one
set of blind-shear rams.
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.
The requirements in §250.442(a) of this part.

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(c) The BOP systems for well-workover operations with the tree removed must be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume
necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without
assistance from a charging system. Accumulator regulators supplied by rig air and without a secondary source of
pneumatic supply, must be equipped with manual overrides, or alternately, other devices provided to ensure capability of
hydraulic operations if rig air is lost;
(2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP
system components and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control station on the rig floor; and
(5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the
valves on the choke-line shall be remotely controlled. At least one of the valves on the kill line shall be remotely
controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed provided two
readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump.
This equipment shall have a pressure rating at least equivalent to the ram preventers.
(d) The minimum BOP-system components for well-workover operations with the tree in place and performed through
the wellhead inside of conventional tubing using small-diameter jointed pipe (usually 3⁄4 inch to 11⁄4 inch) as a work string,
i.e., small-tubing operations, shall include the following:
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) The subsea BOP system for well-workover operations must meet the requirements in §250.442 of this part.
(f) For coiled tubing operations with the production tree in place, you must meet the following minimum requirements
for the BOP system:
(1) BOP system components must be in the following order from the top down:
BOP system
when expected
surface
pressures are
less than or
equal to 3,500
psi
Stripper or
annular-type
well control
component
Hydraulicallyoperated blind
rams
Hydraulicallyoperated shear
rams
Kill line inlet
Hydraulicallyoperated twoway slip rams
Hydraulicallyoperated pipe
rams

BOP system when expected
surface pressures are greater BOP system for wells with returns taken through an outlet on the
than 3,500 psi
BOP stack
Stripper or annular-type well
Stripper or annular-type well control component.
control component

Hydraulically-operated blind
rams

Hydraulically-operated blind rams

Hydraulically-operated shear
rams

Hydraulically-operated shear rams.

Kill line inlet
Kill line inlet.
Hydraulically-operated two-way Hydraulically-operated two-way slip rams.
slip rams
Hydraulically-operated pipe rams.
Hydraulically-operated pipe
rams
Hydraulically-operated blindshear rams. These rams should
be located as close to the tree
as practical

A flow tee or cross.
Hydraulically-operated pipe rams.
Hydraulically-operated blind-shear rams 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 hydraulically-operated combination rams for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the
hydraulically-operated pipe rams.
(4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled
tubing string for all coiled tubing well-workover operations. If you plan to conduct operations without downhole check
valves, you must describe alternate procedures and equipment in Form BSEE-0124, Application for Permit to Modify and
have it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at
least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve
on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The
valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to

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which they are attached, and you must install them between the well control stack and the choke or kill line. For
operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold.
You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close
each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure,
without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged,
including the connections between the well control stack and the first full-opening valve on the choke line and the kill line.
(g) The minimum BOP-system components for well-workover operations with the tree in place and performed by
moving tubing or drill pipe in or out of a well under pressure utilizing equipment specifically designed for that purpose, i.e.,
snubbing operations, shall include the following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool.
(h) An inside BOP or a spring-loaded, back-pressure safety valve and an essentially full-opening, work-string safety
valve in the open position shall be maintained on the rig floor at all times during well-workover operations when the tree is
removed or during well-workover operations with the tree installed and using small tubing as the work string. A wrench to
fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting valves
in the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]
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§250.617   Blowout preventer system testing, records, and drills.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) BOP pressure tests. When you pressure test the BOP system you must conduct a low-pressure test and a highpressure test for each component. You must conduct the low-pressure test before the high-pressure test. For purposes of
this section, BOP system components include ram-type BOP's, related control equipment, choke and kill lines, and
valves, manifolds, strippers, and safety valves. Surface BOP systems must be pressure tested with water.
(1) Low pressure tests. All BOP system components must be successfully tested to a low pressure between 200 and
300 psi. Any initial pressure equal to or greater than 300 psi must be bled back to a pressure between 200 and 300 psi
before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero before starting the test.
(2) High pressure tests. All BOP system components must be successfully tested to the rated working pressure of the
BOP equipment, or as otherwise approved by the District Manager. The annular-type BOP must be successfully tested at
70 percent of its rated working pressure or as otherwise approved by the District Manager.
(3) Other testing requirements. Variable bore pipe rams must be pressure tested against the largest and smallest
sizes of tubulars in use (jointed pipe, seamless pipe) in the well.
(b) Times. The BOP systems shall be tested at the following times:
(1) When installed;
(2) At least every 7 days, alternating between control stations and at staggered intervals to allow each crew to operate
the equipment. If either control system is not functional, further operations shall be suspended until the nonfunctional,
system is operable. The test every 7 days is not required for blind or blind-shear rams. The blind or blind-shear rams shall
be tested at least once every 30 days during operation. A longer period between blowout preventer tests is allowed when
there is a stuck pipe or pressure-control operation and remedial efforts are being performed. The tests shall be conducted
as soon as possible and before normal operations resume. The reason for postponing testing shall be entered into the
operations log.
(3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure
tested.
(c) Drills. All personnel engaged in well-workover operations shall participate in a weekly BOP drill to familiarize crew
members with appropriate safety measures.
(d) Stump tests. You may conduct a stump test for the BOP system on location. A plan describing the stump test
procedures must be included in your Form BSEE-0124, Application for Permit to Modify, and must be approved by the
District Manager.
(e) Coiled tubing tests. You must test the coiled tubing connector to a low pressure of 200 to 300 psi, followed by a
high pressure test to the rated working pressure of the connector or the expected surface pressure, whichever is less.
You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated
working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing,
whichever is less.
(f) Recordings. You must record test pressures during BOP and coiled tubing tests on a pressure chart, or with a

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digital recorder, unless otherwise approved by the District Manager. The test interval for each BOP system component
must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure test for the coiled
tubing string. Your representative at the facility must certify that the charts are correct.
(g) Operations log. The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP
system, system components, and marine risers shall be recorded in the operations log. The BOP tests shall be
documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure
and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that
contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the operations log. For a subsea system, the pod
used during the test shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to
remedy such problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the operation log may instead be referenced in the operations log. All
records including pressure charts, operations log, and referenced documents pertaining to BOP tests, actuations, and
inspections, shall be available for BSEE review at the facility for the duration of well-workover activity. Following
completion of the well-workover activity, all such records shall be retained for a period of 2 years at the facility, at the
lessee's filed office nearest the OCS facility, or at another location conveniently available to the District Manager.
(h) Stump test a subsea BOP system before installation. You must use water to conduct this test. You may use drilling
or completion fluids to conduct subsequent tests of a subsea BOP system. You must perform the initial subsea BOP test
on the seafloor within 30 days of the stump test. You must:
(1) Test all ROV intervention functions on your subsea BOP stack during the stump test. Each ROV must be fully
compatible with the BOP stack ROV intervention panels. You must also test and verify closure of at least one set of rams
during the initial test on the seafloor through an ROV hot stab. You must submit test procedures, including how you will
test each ROV function, with your APM for BSEE District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are capable of actuating, at a minimum, one set of pipe
rams, one set of blind-shear rams, and unlatching the LMRP;
(ii) Notify the appropriate BSEE District Manager a minimum of 72 hours prior to the stump test and initial test on the
seafloor;
(iii) Document all your test results and make them available to BSEE upon request; and
(2) Function test autoshear and deadman systems on your subsea BOP stack during the stump test. You must also
test the deadman system and verify closure of at least one set of blind-shear rams during the initial test on the seafloor.
When you conduct the initial deadman system test on the seafloor you must ensure the well is secure and, if
hydrocarbons have been present, appropriate barriers are in place to isolate hydrocarbons from the wellhead. You must
also have an ROV on bottom during the test. You must:
(i) Submit test procedures with your APM for BSEE District Manager approval. The procedures for these function tests
must include documentation of the controls and circuitry of the system utilized during each test. The procedure must also
describe how the ROV will be utilized during this operation.
(ii) Document the results of each test and make them available to BSEE upon request.
[76 FR 64462, Oct. 18, 2011. Redesignated and amended at 77 FR 50895, 50896, Aug. 22, 2012]
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§250.618   What are my BOP inspection and maintenance requirements?
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) BOP inspections. (1) You must inspect your BOP system to ensure that the equipment functions properly. The
BOP inspections must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections, described in API RP 53,
Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as
specified in §250.198). You must document how you met or exceeded the provisions of Sections 17.10 and 18.10
described in API RP 53, the procedures used, record the results, and make the records available to BSEE upon request.
You must maintain your records on the rig for 2 years from the date the records are created, or for a longer period if
directed by BSEE.
(2) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP
system and marine riser at least once every 3 days if weather and sea conditions permit. You may use television cameras
to inspect subsea equipment. The BSEE District Manager may approve alternate methods and frequencies to inspect a
marine riser.
(b) BOP maintenance. You must maintain your BOP system to ensure that the equipment functions properly. The
BOP maintenance must meet or exceed the provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12
and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment
Systems for Drilling Wells (incorporated by reference as specified in §250.198). You must document how you met or

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eCFR — Code of Federal Regulations

exceeded the provisions of Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management,
described in API RP 53, the procedures used, record the results, and make the records available to BSEE upon request.
You must maintain your records on the rig for 2 years from the date the records are created, or for a longer period if
directed by BSEE.
[77 FR 50896, Aug. 22, 2012]
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§250.619   Tubing and wellhead equipment.
Link to an amendment published at 81 FR 26021, April 29, 2016.

The lessee shall comply with the following requirements during well-workover operations with the tree removed:
(a) No tubing string shall be placed in service or continue to be used unless such tubing string has the necessary
strength and pressure integrity and is otherwise suitable for its intended use.
(b) In the event of prolonged operations such as milling, fishing, jarring, or washing over that could damage the
casing, the casing shall be pressure tested, calipered, or otherwise evaluated every 30 days and the results submitted to
the District Manager.
(c) When reinstalling the tree, you must:
(1) Equip wells to monitor for casing pressure according to the following chart:
you
If you
must
have
equip
.  .  .
.  .  .
so you can monitor .  .  .
(i) fixed the
all annuli (A, B, C, D, etc., annuli).
platform wellhead,
wells,
(ii)
the
the production casing annulus (A annulus).
subsea tubing
wells, head,
(iii)
the
all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the
hybrid* surface production casing riser above the mudline are pressure isolated from each other, provisions must be
wells, wellhead, 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 management requirements in subpart E of this part.
(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and
shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. The tree shall
be equipped with a minimum of one master valve and one surface safety valve in the vertical run of the tree when it is
reinstalled.
(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with §250.801 of this part.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]
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§250.620   Wireline operations.
The lessee shall comply with the following requirements during routine, as defined in §250.601 of this part, and
nonroutine wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that does occur shall
be contained to prevent pollution.
(b) All wireline perforating operations and all other wireline operations where communication exists between the
completed hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator assembly containing at least one wireline
valve.
(c) When the lubricator is initially installed on the well, it shall be successfully pressure tested to the expected shut-in
surface pressure.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50895, Aug. 22, 2012]
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eCFR — Code of Federal Regulations

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