eCFR for 30 CFR Part 250, Subpart E

eCFR — Code of Federal Regulations
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ELECTRONIC CODE OF FEDERAL REGULATIONS
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PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

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Subpart E—Oil and Gas Well-Completion Operations

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§250.500   General requirements.
§250.501   Definition.
§250.502   Equipment movement.
§250.503   Emergency shutdown system.
§250.504   Hydrogen sulfide.
§250.505   Subsea completions.
§250.506   Crew instructions.
§§250.507-250.508   [Reserved]
§250.509   Well-completion structures on fixed platforms.
§250.510   Diesel engine air intakes.
§250.511   Traveling-block safety device.
§250.512   Field well-completion rules.
§250.513   Approval and reporting of well-completion operations.
§250.514   Well-control fluids, equipment, and operations.
§250.515   What BOP information must I submit?
§250.516   Blowout prevention equipment.
§250.517   Blowout preventer system tests, inspections, and maintenance.
§250.518   Tubing and wellhead equipment.

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[A1]

Casing Pressure Management
§250.519   What are the requirements for casing pressure management?
§250.520   How often do I have to monitor for casing pressure?
§250.521   When do I have to perform a casing diagnostic test?
§250.522   How do I manage the thermal effects caused by initial production on a newly completed or recompleted well?
§250.523   When do I have to repeat casing diagnostic testing?
§250.524   How long do I keep records of casing pressure and diagnostic tests?
§250.525   When am I required to take action from my casing diagnostic test?
§250.526   What do I submit if my casing diagnostic test requires action?
§250.527   What must I include in my notification of corrective action?
§250.528   What must I include in my casing pressure request?
§250.529   What are the terms of my casing pressure request?
§250.530   What if my casing pressure request is denied?
§250.531   When does my casing pressure request approval become invalid?

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§250.500   General requirements.
Link to an amendment published at 81 FR 26021, April 29, 2016.

Well-completion operations shall be conducted in a manner to protect against harm or damage to life (including fish

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and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not
leased), the National security or defense, or the marine, coastal, or human environment.
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§250.501   Definition.
When used in this subpart, the following term shall have the meaning given below:
Well-completion operations means the work conducted to establish the production of a well after the productioncasing string has been set, cemented, and pressure-tested.
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§250.502   Equipment movement.
Link to an amendment published at 81 FR 26021, April 29, 2016.

The movement of well-completion 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-completion 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
from which the rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to
removing the blowout preventer (BOP) system and installing the tree.
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§250.503   Emergency shutdown system.
When well-completion operations are conducted on a platform where there are other hydrocarbon-producing wells or
other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the
driller's console or well-servicing unit operator's work station.
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§250.504   Hydrogen sulfide.
When a well-completion 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 completion unit, 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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§250.505   Subsea completions.
No subsea well completion shall be commenced until the lessee obtains written approval from the District Manager in
accordance with §250.513 of this part. That approval shall be based upon a case-by-case determination that the
proposed equipment and procedures will adequately control the well and permit safe production operations.
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§250.506   Crew instructions.
Link to an amendment published at 81 FR 26021, April 29, 2016.

Prior to engaging in well-completion 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 BSEE representatives.
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§§250.507-250.508   [Reserved]
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§250.509   Well-completion 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 proposed
operations. Prior to moving a well-completion rig or 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 platform, and previous stresses to the platform.
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§250.510   Diesel engine air intakes.
Diesel engine air intakes must be equipped with a device to shut down the diesel engine in the event of runaway.
Diesel engines that are continuously attended must be equipped with either remote operated manual or automaticshutdown devices. Diesel engines that are not continuously attended must be equipped with automatic-shutdown devices.
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§250.511   Traveling-block safety device.
All units being used for well-completion operations that have both a traveling block and a crown block must be
equipped with a safety device that is designed to prevent the traveling block from striking the crown block. The device
must be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational
check must be entered in the operations log.
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§250.512   Field well-completion rules.
When geological and engineering information available in a field enables the District Manager to determine specific
operating requirements, field well-completion 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-completion
rules have been established, well-completion operations in the field shall be conducted in accordance with such rules and
other requirements of this subpart. Field well-completion 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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§250.513   Approval and reporting of well-completion operations.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If
completion is planned and the data are available at the time you submit the Application for Permit to Drill and
Supplemental APD Information Sheet (Forms BSEE-0123 and BSEE-0123S), you may request approval for a wellcompletion on those forms (see §§250.410 through 250.418 of this part). If the District Manager has not approved the
completion or if the completion objective or plans have significantly changed, you must submit an Application for Permit to
Modify (Form BSEE-0124) for approval of such operations.
(b) You must submit the following with Form BSEE-0124 (or with Form BSEE-0123; Form BSEE-0123S):
(1) A brief description of the well-completion procedures to be followed, a statement of the expected surface pressure,
and type and weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing zone(s) and the subsurface well-completion
equipment to be used;
(3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not been
previously submitted;
(4) All applicable information required in §250.515.
(5) When the well-completion 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

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(6) Payment of the service fee listed in §250.125.
(c) Within 30 days after completion, you must submit to the District Manager an End of Operations Report (Form
BSEE-0125), including a schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form BSEE-0125 according to §250.186.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012]
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§250.514   Well-control fluids, equipment, and operations.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(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-completion operations and shall not be left unattended at any time unless the well is
shut in and secured.
(b) 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.
(c) When coming out of the hole with drill pipe, 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,
whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe 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 hole shall be utilized.
(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 50894, Aug. 22, 2012]
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§250.515   What BOP information must I submit?
Link to an amendment published at 81 FR 26021, April 29, 2016.

For completion operations, your APM must include the following BOP descriptions:
(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
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;

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(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; and
(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 50894, Aug. 22, 2012]
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§250.516   Blowout prevention equipment.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) The BOP system and 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 BOP 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 or Form BSEE-0123, as
appropriate, 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-completion operations 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.

(c) The BOP systems for well completions 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.
(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 that 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.

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(d) 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-completion operations. 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.
(e) The subsea BOP system for well-completions must meet the requirements in §250.442 of this part.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.517   Blowout preventer system tests, inspections, and maintenance.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(a) BOP pressure testing timeframes. You must pressure test your BOP system:
(1) When installed; and
(2) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before
12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Manager may
require testing every 7 days if conditions or BOP performance warrant.
(b) BOP test pressures. When you test the BOP system, you must conduct a low pressure and a high pressure test
for each BOP component. Each individual pressure test must hold pressure long enough to demonstrate that the tested
component(s) holds the required pressure. The District Manager may approve or require other test pressures or practices.
Required test pressures are as follows:
(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 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 and reinitiate the test. You must conduct the low pressure test before the high pressure test.
(2) For ram-type BOP's, choke manifold, and other BOP equipment, the high pressure test must equal the rated
working pressure of the equipment.
(3) For annular-type BOP's, the high pressure test must equal 70 percent of the rated working pressure of the
equipment.
(c) Duration of pressure test. Each test must hold the required pressure for 5 minutes.
(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable
if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder.
(2) If the equipment does not hold the required pressure during a test, you must remedy the problem and retest the
affected component(s).
(d) Additional BOP testing requirements. You must:
(1) Use water to test the surface BOP system;
(2) 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.
(3) Alternate tests between control stations and pods. If a control station or pod is not functional, you must suspend
further completion operations until that station or pod is operable;
(4) Pressure test the blind or blind-shear ram at least every 30 days;
(5) Function test annulars and rams every 7 days;
(6) Pressure-test variable bore-pipe rams against all sizes of pipe in use, excluding drill collars and bottom-hole tools;
(7) Test affected BOP components following the disconnection or repair of any well-pressure containment seal in the
wellhead or BOP stack assembly;
(8) 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

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(9) 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 all your test results and make them available to BSEE upon request.
(e) Postponing BOP tests. You may postpone a BOP test if you have well-control problems. You must conduct the
required BOP test as soon as possible (i.e., first trip out of the hole) after the problem has been remedied. You must
record the reason for postponing any test in the driller's report.
(f) Weekly crew drills. You must conduct a weekly drill to familiarize all personnel engaged in well-completion
operations with appropriate safety measures.
(g) 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.
(h) 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
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.
(i) BOP test records. You must record the time, date, and results of all pressure tests, actuations, crew drills, and
inspections of the BOP system, system components, and marine riser in the driller's report. In addition, you must:
(1) Record BOP test pressures on pressure charts;
(2) Have your onsite representative certify (sign and date) BOP test charts and reports as correct;
(3) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test.
You may reference a BOP test plan if it is available at the facility;
(4) Identify the control station or pod used during the test;
(5) Identify any problems or irregularities observed during BOP system and equipment testing and record actions
taken to remedy the problems or irregularities;
(6) Retain all records including pressure charts, driller's report, and referenced documents pertaining to BOP tests,
actuations, and inspections at the facility for the duration of the completion activity; and
(7) After completion of the well, you must retain all the records listed in paragraph (i)(6) of this section for a period of 2
years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the
District Manager.
(j) Alternate methods. The District Manager may require, or approve, more frequent testing, as well as different test
pressures and inspection methods, or other practices.
[76 FR 64462, Oct. 18, 2011. Redesignated and amended at 77 FR 50894, 50895, Aug. 22, 2012]
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§250.518   Tubing and wellhead equipment.
Link to an amendment published at 81 FR 26021, April 29, 2016.

(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

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casing, the casing shall be pressure-tested, calipered, or otherwise evaluated every 30 days and the results submitted to
the District Manager.
(c) When the tree is installed, you must equip wells to monitor for casing pressure according to the following chart:
you
must
If you
equip
.  .  .
.  .  .
so you can monitor .  .  .
(1) fixed the
all annuli (A, B, C, D, etc., annuli).
platform wellhead,
wells,
(2)
the
the production casing annulus (A annulus).
subsea tubing
wells,
head,
(3)
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.
(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. New wells
completed as flowing or gas-lift wells shall be equipped with a minimum of one master valve and one surface safety valve,
installed above the master valve, in the vertical run of the tree.
(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 50894, Aug. 22, 2012]
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Casing PressUre Management
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§250.519   What are the requirements for casing pressure management?
Once you install your wellhead, you must meet the casing pressure management requirements of API RP 90 (as
incorporated by reference in §250.198) and the requirements of §§250.519 through 250.530. If there is a conflict between
API RP 90 and the casing pressure requirements of this subpart, you must follow the requirements of this subpart.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.520   How often do I have to monitor for casing pressure?
You must monitor for casing pressure in your well according to the following table:

If you have .  .  .
(a) fixed platform wells,
(b) subsea wells,
(c) hybrid wells,

you must
monitor .  .  .
monthly,
continuously,
continuously,

(d) wells operating under a casing pressure request on a daily,
manned fixed platform,
(e) wells operating under a casing pressure request on an weekly,
unmanned fixed platform,

with a minimum one pressure data point
recorded per .  .  .
month for each casing.
day for the production casing.
day for each riser and/or the production
casing.
day for each casing.
week for each casing.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.521   When do I have to perform a casing diagnostic test?
(a) You must perform a casing diagnostic test within 30 days after first observing or imposing casing pressure

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according to the following table:
If you have a
.  .  .
you must perform a casing diagnostic test if .  .  .
(1) fixed platform the casing pressure is greater than 100 psig.
well,
(2) subsea well, the measurable casing pressure is greater than the external hydrostatic pressure plus 100 psig
measured at the subsea wellhead.
(3) hybrid well, a riser or the production casing pressure is greater than 100 psig measured at the surface.
(b) You are exempt from performing a diagnostic pressure test for the production casing on a well operating under
active gas lift.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.522   How do I manage the thermal effects caused by initial production on a newly completed or recompleted
well?
A newly completed or recompleted well often has thermal casing pressure during initial startup. Bleeding casing
pressure during the startup process is considered a normal and necessary operation to manage thermal casing pressure;
therefore, you do not need to evaluate these operations as a casing diagnostic test. After 30 days of continuous
production, the initial production startup operation is complete and you must perform casing diagnostic testing as required
in §§250.520 and 250.522.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.523   When do I have to repeat casing diagnostic testing?
Casing diagnostic testing must be repeated according to the following table:
When .  .  .
you must repeat diagnostic testing .  .  .
(a) your casing pressure request approved term has expired,
immediately.
(b) your well, previously on gas lift, has been shut-in or returned to immediately on the production casing (A annulus).
flowing status without gas lift for more than 180 days,
The production casing (A annulus) of wells on active
gas lift are exempt from diagnostic testing.
(c) your casing pressure request becomes invalid,
within 30 days.
(d) a casing or riser has an increase in pressure greater than 200 within 30 days.
psig over the previous casing diagnostic test,
(e) after any corrective action has been taken to remediate
within 30 days.
undesirable casing pressure, either as a result of a casing
pressure request denial or any other action,
(f) your fixed platform well production casing (A annulus) has
once per year, not to exceed 12 months between
pressure exceeding 10 percent of its minimum internal yield
tests.
pressure (MIYP), except for production casings on active gas lift,
(g) your fixed platform well's outer casing (B, C, D, etc., annuli) has once every 5 years, at a minimum.
a pressure exceeding 20 percent of its MIYP,
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.524   How long do I keep records of casing pressure and diagnostic tests?
Records of casing pressure and diagnostic tests must be kept at the field office nearest the well for a minimum of 2
years. The last casing diagnostic test for each casing or riser must be retained at the field office nearest the well until the
well is abandoned.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.525   When am I required to take action from my casing diagnostic test?
You must take action if you have any of the following conditions:

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(a) Any fixed platform well with a casing pressure exceeding its maximum allowable wellhead operating pressure
(MAWOP);
(b) Any fixed platform well with a casing pressure that is greater than 100 psig and that cannot bleed to 0 psig through
a 1⁄2 -inch needle valve within 24 hours, or is not bled to 0 psig during a casing diagnostic test;
(c) Any well that has demonstrated tubing/casing, tubing/riser, casing/casing, riser/casing, or riser/riser
communication;
(d) Any well that has sustained casing pressure (SCP) and is bled down to prevent it from exceeding its MAWOP,
except during initial startup operations described in §250.521;
(e) Any hybrid well with casing or riser pressure exceeding 100 psig; or
(f) Any subsea well with a casing pressure 100 psig greater than the external hydrostatic pressure at the subsea
wellhead.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.526   What do I submit if my casing diagnostic test requires action?
Within 14 days after you perform a casing diagnostic test requiring action under §250.524:
You must submit
either .  .  .
(a) a notification of
corrective action;
or,
(b) a casing
pressure request,

to the appropriate .  .  .
District Manager and copy the
Regional Supervisor, Field
Operations,
Regional Supervisor, Field
Operations,

and it must
include .  .  . You must also .  .  .
requirements submit an Application for Permit to Modify or
under
Corrective Action Plan within 30 days of the
§250.526,
diagnostic test.
requirements
under
§250.527.

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.527   What must I include in my notification of corrective action?
The following information must be included in the notification of corrective action:
(a) Lessee or Operator name;
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.528   What must I include in my casing pressure request?
The following information must be included in the casing pressure request:
(a) API number;
(b) Lease number;
(c) Area name and OCS block number;
(d) Well number;
(e) Company name and mailing address;
(f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
(g) All casing/riser calculated MAWOPs;
(h) All casing/riser pre-bleed down pressures;
(i) Shut-in tubing pressure;

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(j) Flowing tubing pressure;
(k) Date and the calculated daily production rate during last well test (oil, gas, basic sediment, and water);
(l) Well status (shut-in, temporarily abandoned, producing, injecting, or gas lift);
(m) Well type (dry tree, hybrid, or subsea);
(n) Date of diagnostic test;
(o) Well schematic;
(p) Water depth;
(q) Volumes and types of fluid bled from each casing or riser evaluated;
(r) Type of diagnostic test performed:
(1) Bleed down/buildup test;
(2) Shut-in the well and monitor the pressure drop test;
(3) Constant production rate and decrease the annular pressure test;
(4) Constant production rate and increase the annular pressure test;
(5) Change the production rate and monitor the casing pressure test; and
(6) Casing pressure and tubing pressure history plot;
(s) The casing diagnostic test data for all casing exceeding 100 psig;
(t) Associated shoe strengths for casing shoes exposed to annular fluids;
(u) Concentration of any H2S that may be present;
(v) Whether the structure on which the well is located is manned or unmanned;
(w) Additional comments; and
(x) Request date.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.529   What are the terms of my casing pressure request?
Casing pressure requests are approved by the Regional Supervisor, Field Operations, for a term to be determined by
the Regional Supervisor on a case-by-case basis. The Regional Supervisor may impose additional restrictions or
requirements to allow continued operation of the well.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.530   What if my casing pressure request is denied?
(a) If your casing pressure request is denied, then the operating company must submit plans for corrective action to
the respective District Manager within 30 days of receiving the denial. The District Manager will establish a specific time
period in which this corrective action will be taken. You must notify the respective District Manager within 30 days after
completion of your corrected action.
(b) You must submit the casing diagnostic test data to the appropriate Regional Supervisor, Field Operations, within
14 days of completion of the diagnostic test required under §250.522(e).
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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§250.531   When does my casing pressure request approval become invalid?
A casing pressure request becomes invalid when:
(a) The casing or riser pressure increases by 200 psig over the approved casing pressure request pressure;

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(b) The approved term ends;
(c) The well is worked-over, side-tracked, redrilled, recompleted, or acid stimulated;
(d) A different casing or riser on the same well requires a casing pressure request; or
(e) A well has more than one casing operating under a casing pressure request and one of the casing pressure
requests become invalid, then all casing pressure requests for that well become invalid.
[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012]
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