eCFR for 30 CFR 250 subpart Q

eCFR — Code of Federal Regulations
About GPO

|   Newsroom/Media

|  
Congressional Relations

|  
Inspector General

|  
Careers

|  
Contact

|  
askGPO

|  
Help

Home

|  
Customers

|  
Vendors

|  
Libraries

FDsys:
GPO's Federal Digital System
About FDsys
Search Government Publications
Browse Government Publications

ELECTRONIC CODE OF FEDERAL REGULATIONS
View past updates to the e-CFR.
Click here to learn more.

e-CFR Navigation Aids

e-CFR data is current as of August 17, 2016

Browse / Search Previous

• Browse
• Simple Search

Title 30 → Chapter II → Subchapter B → Part 250 → Subpart Q

• Advanced Search
* Boolean

Browse Previous | Browse Next

  * Proximity

Title 30: Mineral Resources

• Search History

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

• Search Tips
• Corrections
• Latest Updates

Subpart Q—Decommissioning Activities

• User Info

Contents

• FAQs

General

• Agency List
• Incorporation By Reference
Related Resources
The Code of Federal Regulations
(CFR) annual edition is the codification
of the general and permanent rules
published in the Federal Register by the
departments and agencies of the
Federal Government produced by the
Office of the Federal Register (OFR) and
the Government Publishing Office.
Download the Code of Federal
Regulations in XML.
Parallel Table of Authorities and Rules
for the Code of Federal Regulations and
the United States Code
Text | PDF
Find, review, and submit comments on
Federal rules that are open for comment
and published in the Federal Register
using Regulations.gov.
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.
[A2]

§250.1700   What do the terms “decommissioning”, “obstructions”, and “facility” mean?
§250.1701   Who must meet the decommissioning obligations in this subpart?
§250.1702   When do I accrue decommissioning obligations?
§250.1703   What are the general requirements for decommissioning?
§250.1704   What decommissioning applications and reports must I submit and when must I submit them?
§250.1705   [Reserved]
§250.1706   Coiled tubing and snubbing operations.
§§250.1707-250.1709   [Reserved]

PermanentlY Plugging Wells
§250.1710   When must I permanently plug all wells on a lease?
§250.1711   When will BSEE order me to permanently plug a well?
§250.1712   What information must I submit before I permanently plug a well or zone?
§250.1713   Must I notify BSEE before I begin well plugging operations?
§250.1714   What must I accomplish with well plugs?
§250.1715   How must I permanently plug a well?
§250.1716   To what depth must I remove wellheads and casings?
§250.1717   [Reserved]

TemporarY Abandoned Wells
§250.1721   If I temporarily abandon a well that I plan to re-enter, what must I do?
§250.1722   If I install a subsea protective device, what requirements must I meet?
§250.1723   What must I do when it is no longer necessary to maintain a well in temporary abandoned status?

Removing Platforms and Other Facilities
§250.1725   When do I have to remove platforms and other facilities?
§250.1726   When must I submit an initial platform removal application and what must it include?
§250.1727   What information must I include in my final application to remove a platform or other facility?
§250.1728   To what depth must I remove a platform or other facility?
§250.1729   After I remove a platform or other facility, what information must I submit?
§250.1730   When might BSEE approve partial structure removal or toppling in place?
§250.1731   Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE?

Site Clearance for Wells, Platforms, and Other Facilities
§250.1740   How must I verify that the site of a permanently plugged well, removed platform, or other removed facility is clear of obstructions?
§250.1741   If I drag a trawl across a site, what requirements must I meet?
§250.1742   What other methods can I use to verify that a site is clear?
§250.1743   How do I certify that a site is clear of obstructions?

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

Pipeline Decommissioning
§250.1750   When may I decommission a pipeline in place?
§250.1751   How do I decommission a pipeline in place?
§250.1752   How do I remove a pipeline?
§250.1753   After I decommission a pipeline, what information must I submit?
§250.1754   When must I remove a pipeline decommissioned in place?

Back to Top

GEnEral
Back to Top

§250.1700   What do the terms “decommissioning”, “obstructions”, and “facility” mean?
(a) Decommissioning means:
(1) Ending oil, gas, or sulphur operations; and
(2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of BSEE and
other agencies that have jurisdiction over decommissioning activities.
(b) Obstructions mean structures, equipment, or objects that were used in oil, gas, or sulphur operations or marine
growth that, if left in place, would hinder other users of the OCS. Obstructions may include, but are not limited to, shell
mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies,
umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline
valves, and power cables.
(c) Facility means any installation other than a pipeline used for oil, gas, or sulphur activities that is permanently or
temporarily attached to the seabed on the OCS. Facilities include production and pipeline risers, templates, pilings, and
any other facility or equipment that constitutes an obstruction such as jumper assemblies, termination skids, umbilicals,
anchors, and mooring lines.
Back to Top

§250.1701   Who must meet the decommissioning obligations in this subpart?
(a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning
obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and
until each obligation is met.
(b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on
their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met.
(c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under
the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way.
Back to Top

§250.1702   When do I accrue decommissioning obligations?
You accrue decommissioning obligations when you do any of the following:
(a) Drill a well;
(b) Install a platform, pipeline, or other facility;
(c) Create an obstruction to other users of the OCS;
(d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been
permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction;
(e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an
obstruction; or
(f) Re-enter a well that was previously plugged according to this subpart.
Back to Top

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

§250.1703   What are the general requirements for decommissioning?
When your facilities are no longer useful for operations, you must:
(a) Get approval from the appropriate District Manager before decommissioning wells and from the Regional
Supervisor before decommissioning platforms and pipelines or other facilities;
(b) Permanently plug all wells. Permanently installed packers and bridge plugs must comply with API Spec. 11D1 (as
incorporated by reference in §250.198);
(c) Remove all platforms and other facilities, except as provided in §§250.1725(a) and 250.1730.
(d) Decommission all pipelines;
(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations;
(f) Follow all applicable requirements of subpart G of this part; and
(g) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of
the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26037, Apr. 29 2016]
Back to Top

§250.1704   What decommissioning applications and reports must I submit and when must I submit them?
You must submit decommissioning applications, receive approval of those applications, and submit subsequent
reports according to the requirements and deadlines in the following table.
DEcommissioning Applications and REports TaBlE
Decommissioning
applications and
reports
(a) Initial platform
removal application [not
required in the Gulf of
Mexico OCS Region]

When to submit
In the Pacific OCS Region
or Alaska OCS Region,
submit the application to
the Regional Supervisor
at least 2 years before
production is projected to
cease
(b) Final removal
Before removing a
application for a platform platform or other facility in
or other facility
the Gulf of Mexico OCS
Region, or not more than
2 years after the submittal
of an initial platform
removal application to the
Pacific OCS Region and
the Alaska OCS Region
(c) Post-removal report Within 30 days after you
for a platform or other
remove a platform or
facility
other facility
(d) Pipeline
Before you decommission
decommissioning
a pipeline
application
(e) Post-pipeline
Within 30 days after you
decommissioning report decommission a pipeline
(f) Site clearance report Within 30 days after you
for a platform or other
complete site clearance
facility
verification activities
(g) Form BSEE-0124,
(1) Before you temporarily
Application for Permit to abandon or permanently
Modify (APM). The
plug a well or zone,
submission of your APM
must be accompanied
by payment of the
service fee listed in
§250.125;

(2) Before you install a
subsea protective device,

(3) Before you remove
any casing stub or mud
line suspension

Instructions
Include information required under §250.1726.

Include information required under §250.1727.

Include information required under §250.1729.

Include information required under §250.1751(a) or §250.1752(a), as
applicable.
Include information required under §250.1753.
Include information required under §250.1743(b).

(i) Include information required under §§250.1712 and 250.1721.
(ii) When using a BOP for abandonment operations, include
information required under §250.731.

Refer to §250.1722(a).
Refer to §250.1723.

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

equipment and any
subsea protective device,
(h) Form BSEE-0125,
(1) Within 30 days after
End of Operations
you complete a protective
Report (EOR);
device trawl test,

(2) Within 30 days after
you complete site
clearance verification
activities,
(i) A certified summary Within 120 days after
of expenditures for
completion of each
permanently plugging
decommissioning activity
any well, removal of any specified in this paragraph
platform or other facility,
and clearance of any
site after wells have
been plugged or
platforms or facilities
removed
(j) If requested by the
Within a reasonable time
Regional Supervisor,
as determined by the
additional information in Regional Supervisor
support of any
decommissioning
activity expenditures
included in a summary
submitted under
paragraph (h) of this
section

Include information required under §250.1722(d).

Include information required under §250.1743(a).

Submit to the Regional Supervisor a complete summary of
expenditures actually incurred for each decommissioning activity
(including, but not limited to, the use of rigs, vessels, equipment,
supplies and materials; transportation of any kind; personnel; and
services). Include in, or attach to, the summary a certified statement
by an authorized representative of your company attesting to the
truth, accuracy and completeness of the summary. The Regional
Supervisor may provide specific instructions or guidance regarding
how to submit the certified summary.
The Regional Supervisor will review the summary and may provide
specific instructions or guidance regarding the submission of
additional information (including, but not limited to, copies of
contracts and invoices), if requested, to complete or otherwise
support the summary.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012; 80 FR 75810, Dec. 4, 2015; 81 FR 26037, Apr. 29, 2016]
Back to Top

§250.1705   [Reserved]
Back to Top

§250.1706   Coiled tubing and snubbing operations.
If you use a BOP for any well abandonment operations, your BOP must meet the following requirements:
(a) 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
BOP system when expected
equal to 3,500 surface pressures are greater
psi
than 3,500 psi
(i) Stripper or
Stripper or annular-type wellannular-type
control component,
well-control
component,
(ii) Hydraulically- Hydraulically-operated blind
operated blind
rams,
rams,
(iii) Hydraulically- Hydraulically-operated shear
operated shear rams,
rams,
(iv) Kill line inlet, Kill line inlet,
(v) Hydraulically- Hydraulically-operated two-way
operated twoslip rams,
way slip rams,
(vi) Hydraulically- Hydraulically-operated pipe
operated pipe
rams.
rams,
Hydraulically-operated blind-

BOP system for wells with returns taken through an outlet on the
BOP stack
Stripper or annular-type well-control component.

Hydraulically-operated blind rams.

Hydraulically-operated shear rams.

Kill line inlet.
Hydraulically-operated two-way slip rams.
Hydraulically-operated pipe rams.
A flow tee or cross.
Hydraulically-operated pipe rams.
Hydraulically-operated blind-shear rams on wells with surface

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

shear rams. These rams should pressures >3,500 psi. As an option, the pipe rams can be placed
be located as close to the tree below the blind-shear rams. The blind-shear rams should be located
as practical,
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 abandonment 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 BSEE 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 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.
(b) The minimum BOP system components for well abandonment 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, must 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.
(c) An inside BOP or a spring-loaded, back-pressure safety valve, and an essentially full-opening, work-string safety
valve in the open position must be maintained on the rig floor at all times during well abandonment operations when the
tree is removed or during well abandonment operations with the tree installed and using small tubing as the work string. A
wrench to fit the work-string safety valve must be readily available. Proper connections must be readily available for
inserting valves in the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations.
[77 FR 50897, Aug. 22, 2012, as amended at 81 FR 26037, Apr. 29, 2016]
Back to Top

§§250.1707-250.1709   [Reserved]
Back to Top

PErmanEntlY PlUgging WElls
Back to Top

§250.1710   When must I permanently plug all wells on a lease?
You must permanently plug all wells on a lease within 1 year after the lease terminates.
Back to Top

§250.1711   When will BSEE order me to permanently plug a well?
BSEE will order you to permanently plug a well if that well:
(a) Poses a hazard to safety or the environment; or
(b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities.
Back to Top

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

§250.1712   What information must I submit before I permanently plug a well or zone?
Before you permanently plug a well or zone, you must submit form BSEE-0124, Application for Permit to Modify, to
the appropriate District Manager and receive approval. A request for approval must contain the following information:
(a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional
Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil,
gas, or sulfur;
(b) Recent well test data and pressure data, if available;
(c) Maximum possible surface pressure, and how it was determined;
(d) Type and weight of well-control fluid you will use;
(e) A description of the work;
(f) A current and proposed well schematic and description that includes:
(1) Well depth;
(2) All perforated intervals that have not been plugged;
(3) Casing and tubing depths and details;
(4) Subsurface equipment;
(5) Estimated tops of cement (and the basis of the estimate) in each casing annulus;
(6) Plug locations;
(7) Plug types;
(8) Plug lengths;
(9) Properties of mud and cement to be used;
(10) Perforating and casing cutting plans;
(11) Plug testing plans;
(12) Casing removal (including information on explosives, if used);
(13) Proposed casing removal depth; and
(14) Your plans to protect archaeological and sensitive biological features, including anchor damage during plugging
operations, a brief assessment of the environmental impacts of the plugging operations, and the procedures and mitigation
measures you will take to minimize such impacts; and
(g) Certification by a Registered Professional Engineer of the well abandonment design and procedures and that all
plugs meet the requirements in the table in §250.1715. In addition to the requirements of §250.1715, the Registered
Professional Engineer must also certify the design will include two independent barriers, one of which must be a
mechanical barrier, in the center wellbore as described in §250.420(b)(3). The Registered Professional Engineer must be
registered in a State of the United States and have sufficient expertise and experience to perform the certification. You
must submit this certification with your APM (Form BSEE-0124).
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012]
Back to Top

§250.1713   Must I notify BSEE before I begin well plugging operations?
You must notify the appropriate District Manager at least 48 hours before beginning operations to permanently plug a
well.
Back to Top

§250.1714   What must I accomplish with well plugs?
You must ensure that all well plugs:
(a) Provide downhole isolation of hydrocarbon and sulphur zones;
(b) Protect freshwater aquifers; and
(c) Prevent migration of formation fluids within the wellbore or to the seafloor.

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations
Back to Top

§250.1715   How must I permanently plug a well?
(a) You must permanently plug wells according to the table in this section. The District Manager may require
additional well plugs as necessary.
PErmanEnt WEll PlUgging REqUirEmEnts
If you have .  .  .
(1) Zones in open hole,

Then you must use .  .  .
Cement plug(s) set from at least 100 feet below the bottom to 100 feet above the top of oil,
gas, and fresh-water zones to isolate fluids in the strata
(2) Open hole below
(i) A cement plug, set by the displacement method, at least 100 feet above and below
casing,
deepest casing shoe;

(ii) A cement retainer with effective back-pressure control set 50 to 100 feet above the
casing shoe, and a cement plug that extends at least 100 feet below the casing shoe and at
least 50 feet above the retainer; or

(iii) A bridge plug set 50 feet to 100 feet above the shoe with 50 feet of cement on top of the
bridge plug, for expected or known lost circulation conditions
(3) A perforated zone that (i) A method to squeeze cement to all perforations;
is currently open and not
(ii) A cement plug set by the displacement method, at least 100 feet above to 100 feet below
previously squeezed or
the perforated interval, or down to a casing plug, whichever is less; or
isolated,
(iii) If the perforated zones are isolated from the hole below, you may use any of the plugs
specified in paragraphs (a)(3)(iii)(A) through (E) of this section instead of those specified in
paragraphs (a)(3)(i) and (a)(3)(ii) of this section.

(A) A cement retainer with effective back-pressure control set 50 to 100 feet above the top of
the perforated interval, and a cement plug that extends at least 100 feet below the bottom of
the perforated interval with at least 50 feet of cement above the retainer;

(B) A casing bridge plug set 50 to 100 feet above the top of the perforated interval and at
least 50 feet of cement on top of the bridge plug;

(C) A cement plug at least 200 feet in length, set by the displacement method, with the
bottom of the plug no more than 100 feet above the perforated interval;

(D) A through-tubing basket plug set no more than 100 feet above the perforated interval
with at least 50 feet of cement on top of the basket plug; or

(E) A tubing plug set no more than 100 feet above the perforated interval topped with a
sufficient volume of cement so as to extend at least 100 feet above the uppermost packer in
the wellbore and at least 300 feet of cement in the casing annulus immediately above the
packer.
(4) A casing stub where the (i) A cement plug set at least 100 feet above and below the stub end;
stub end is within the
casing,

(ii) A cement retainer or bridge plug set at least 50 to 100 feet above the stub end with at
least 50 feet of cement on top of the retainer or bridge plug; or

(iii) A cement plug at least 200 feet long with the bottom of the plug set no more than 100
feet above the stub end.
(5) A casing stub where the A plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable.
stub end is below the
casing,
(6) An annular space that A cement plug at least 200 feet long set in the annular space. For a well completed above
communicates with open
the ocean surface, you must pressure test each casing annulus to verify isolation.
hole and extends to the
mud line,
(7) A subsea well with
A cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4)
unsealed annulus,
and (a)(5) of this section.
(8) A well with casing,
A cement surface plug at least 150 feet long set in the smallest casing that extends to the
mud line with the top of the plug no more than 150 feet below the mud line.
(9) Fluid left in the hole,
A fluid in the intervals between the plugs that is dense enough to exert a hydrostatic
pressure that is greater than the formation pressures in the intervals.
(10) Permafrost areas,
(i) A fluid to be left in the hole that has a freezing point below the temperature of the
permafrost, and a treatment to inhibit corrosion; and

(ii) Cement plugs designed to set before freezing and have a low heat of hydration.
(11) Removed the barriers Two independent barriers, one of which must be a mechanical barrier, in the center wellbore
required in §250.420(b)(3) as described in §250.420(b)(3) once the well is to be placed in a permanent or temporary
for the well to be completed abandonment.
(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The
plug must pass one of the following tests to verify plug integrity:
(1) A pipe weight of at least 15,000 pounds on the plug; or
(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

percent in 15 minutes. The District Manager may require you to tests other plug(s).
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012; 81 FR 26038, Apr. 29, 2016]
Back to Top

§250.1716   To what depth must I remove wellheads and casings?
(a) Unless the District Manager approves an alternate depth under paragraph (b) of this section, you must remove all
wellheads and casings to at least 15 feet below the mud line.
(b) The District Manager may approve an alternate removal depth if:
(1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical
and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not
expected; or
(2) You determine, and BSEE concurs, that you must use divers, and the seafloor sediment stability poses safety
concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
Back to Top

§250.1717   [Reserved]
Back to Top

TEmporarY ABandonEd WElls
Back to Top

§250.1721   If I temporarily abandon a well that I plan to re-enter, what must I do?
You may temporarily abandon a well when it is necessary for proper development and production of a lease. To
temporarily abandon a well, you must do all of the following:
(a) Submit form BSEE-0124, Application for Permit to Modify, and the applicable information required by §250.1712 to
the appropriate District Manager and receive approval;
(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in §250.1715,
except for §250.1715(a)(8). You do not need to sever the casings, remove the wellhead, or clear the site;
(c) Set a bridge plug or a cement plug at least 100-feet long at the base of the deepest casing string, unless the
casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement
plug to extend below the casing shoe into the open hole;
(d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing.
The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. BSEE may consider
approving alternate requirements for subsea wells case-by-case;
(e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according
to U.S. Coast Guard (USCG) requirements;
(f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or
other obstructions remaining above the seafloor by using one of the following methods, as approved by the District
Manager or Regional Supervisor:
(1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation;
(2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or
(3) A subsea protective device that meets the requirements in §250.1722.
(g) Submit certification by a Registered Professional Engineer of the well abandonment design and procedures and
that all plugs meet the requirements of paragraph (b) of this section. In addition to the requirements of paragraph (b) of this
section, the Registered Professional Engineer must also certify the design will include two independent barriers, one of
which must be a mechanical barrier, in the center wellbore as described in §250.420(b)(3). The Registered Professional
Engineer must be registered in a State of the United States and have sufficient expertise and experience to perform the
certification. You must submit this certification with your APM (Form BSEE-0124) required by §250.1712 of this part.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50900, Aug. 22, 2012; 81 FR 26038, Apr. 29, 2016]

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations
Back to Top

§250.1722   If I install a subsea protective device, what requirements must I meet?
If you install a subsea protective device under §250.1721(f)(3), you must install it in a manner that allows fishing gear
to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.
(a) Use form BSEE-0124, Application for Permit to Modify to request approval from the appropriate District Manager
to install a subsea protective device.
(b) The protective device may not extend more than 10 feet above the seafloor (unless BSEE approves otherwise).
(c) You must trawl over the protective device when you install it (adhere to the requirements at §250.1741(d) through
(h)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District
Manager within 5 days and perform remedial action within 30 days of the trawl;
(d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the
appropriate District Manager using form BSEE-0124, Application for Permit to Modify that includes the following:
(1) The date(s) the trawling test was performed and the vessel that was used;
(2) A plat at an appropriate scale showing the trawl lines;
(3) A description of the trawling operation and the net(s) that were used;
(4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl;
(5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of
any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion
of any snag removals requiring diver assistance; and
(6) A letter signed by your authorized representative stating that he/she witnessed the trawling test.
(e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark
the site with a buoy installed according to the USCG requirements.
(f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or
to permanently plug the well.
(g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths less
than 300 feet remain protected.
(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or
perform a trawl test at least annually.
(2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl
does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line
suspension equipment, or the trawl, notify the appropriate District Manager within 5 days, and perform the necessary
remedial work within 30 days of discovery of the problem.
(3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method
used and a description of any remedial work you will perform or have performed.
(h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use
either:
(1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR
part 67 (or its successor); or
(2) A design and installation method that has been proven successful by trawl testing of previous protective devices of
the same design and installed in areas with similar bottom conditions.
Back to Top

§250.1723   What must I do when it is no longer necessary to maintain a well in temporary abandoned status?
If you or BSEE determines that continued maintenance of a well in a temporary abandoned status is not necessary for
the proper development or production of a lease, you must:
(a) Promptly and permanently plug the well according to §250.1715;
(b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit
a request for approval to perform such work to the appropriate District Manager using form BSEE-0124, Application for
Permit to Modify; and
(c) Clear the well site according to §§250.1740 through 250.1742.

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations
Back to Top

REmoving Platforms and OthEr FacilitiEs
Back to Top

§250.1725   When do I have to remove platforms and other facilities?
(a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates,
unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms,
well jackets, single-well caissons, and pipeline accessory platforms. Other activities include those supporting OCS oil and
gas production and transportation, as well as other energy-related or marine-related uses (including LNG) for which
adequate financial assurance for decommissioning has been provided to a Federal agency which has given BSEE a
commitment that it has and will exercise authority to compel the performance of decommissioning within a time following
cessation of the new use acceptable to BSEE. The approval will specify:
(1) Whether you must continue to maintain any financial assurance for decommissioning; and
(2) Whether, and under what circumstances, you must perform any decommissioning not performed by the new
facility owner/user.
(b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional
Supervisor for approval and include the information listed in §250.1727.
(c) You must remove a platform or other facility according to the approved application.
(d) You must flush all production risers with seawater before you remove them.
(e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations.
Back to Top

§250.1726   When must I submit an initial platform removal application and what must it include?
An initial platform removal application is required only for leases and pipeline rights-of-way in the Pacific OCS Region
or the Alaska OCS Region. It must include the following information:
(a) Platform or other facility removal procedures, including the types of vessels and equipment you will use;
(b) Facilities (including pipelines) you plan to remove or leave in place;
(c) Platform or other facility transportation and disposal plans;
(d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment
of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the
impacts; and
(e) A projected decommissioning schedule.
Back to Top

§250.1727   What information must I include in my final application to remove a platform or other facility?
You must submit to the Regional Supervisor, a final application for approval to remove a platform or other facility.
Your application must be accompanied by payment of the service fee listed in §250.125. If you are proposing to use
explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the
application. Include the following information in the final removal application, as applicable:
(a) Identification of the applicant including:
(1) Lease operator/pipeline right-of-way holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification of the structure you are removing including:
(1) Platform Name/BSEE Complex ID Number;
(2) Location (lease/right-of-way, area, block, and block coordinates);

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

(3) Date installed (year);
(4) Proposed date of removal (Month/Year); and
(5) Water depth.
(c) Description of the structure you are removing including:
(1) Configuration (attach a photograph or a diagram);
(2) Size;
(3) Number of legs/casings/pilings;
(4) Diameter and wall thickness of legs/casings/pilings;
(5) Whether piles are grouted inside or outside;
(6) Brief description of soil composition and condition;
(7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and
(8) The maximum removal lift weight and estimated number of main lifts to remove the structure.
(d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure.
(e) Identification of the purpose, including:
(1) Lease expiration/right-of-way relinquishment date; and
(2) Reason for removing the structure.
(f) A description of the removal method, including:
(1) A brief description of the method you will use;
(2) If you are using explosives, the following:
(i) Type of explosives;
(ii) Number and sizes of charges;
(iii) Whether you are using single shot or multiple shots;
(iv) If multiple shots, the sequence and timing of detonations;
(v) Whether you are using a bulk or shaped charge;
(vi) Depth of detonation below the mud line; and
(vii) Whether you are placing the explosives inside or outside of the pilings;
(3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and
marine mammals, a description of the proposed detection method; and
(4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations.
(g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform.
(h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent
observations of turtles or marine mammals at the structure site.
(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief
assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take
to minimize such impacts.
(j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine
life.
Back to Top

§250.1728   To what depth must I remove a platform or other facility?
(a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove
all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line.
(b) The Regional Supervisor may approve an alternate removal depth if:
(1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical
and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

expected; or
(2) You determine, and BSEE concurs, that you must use divers and the seafloor sediment stability poses safety
concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
Back to Top

§250.1729   After I remove a platform or other facility, what information must I submit?
Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional
Supervisor that includes the following:
(a) A summary of the removal operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the types and amount of explosives you
used in removing the platform or other facility were consistent with those set forth in the approved removal application.
Back to Top

§250.1730   When might BSEE approve partial structure removal or toppling in place?
The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by
approving partial structure removal or toppling in place for conversion to an artificial reef if you meet the following
conditions:
(a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit
from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and
(b) You satisfy any U.S. Coast Guard (USCG) navigational requirements for the structure.
Back to Top

§250.1731   Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE?
(a) The holder of an Alternate Use RUE issued under 30 CFR part 585 is responsible for all decommissioning
obligations that accrue following the issuance of the Alternate Use RUE and which pertain to the Alternate Use RUE. See
30 CFR part 585, subpart J, for additional information concerning the decommissioning responsibilities of an Alternate Use
RUE grant holder.
(b) The lessee under the lease originally issued under 30 CFR part 556 will remain responsible for decommissioning
obligations that accrued before issuance of the Alternate Use RUE, as well as for decommissioning obligations that accrue
following issuance of the Alternate Use RUE to the extent associated with continued activities authorized under this part.
(c) If a lease issued under 30 CFR part 556 is cancelled or otherwise terminated under any provision of this
subchapter, the lessee, upon our approval, may defer removal of any OCS facility within the lease area that is subject to
an Alternate Use RUE. If we elect to grant such a deferral, the lessee remains responsible for removing the facility upon
termination of the Alternate Use RUE and will be required to retain sufficient bonding or other financial assurances to
ensure that the structure is removed or otherwise decommissioned in accordance with the provisions of this subpart.
Back to Top

SitE ClEarancE for WElls, Platforms, and OthEr FacilitiEs
Back to Top

§250.1740   How must I verify that the site of a permanently plugged well, removed platform, or other removed
facility is clear of obstructions?
Within 60 days after you permanently plug a well or remove a platform or other facility, you must verify that the site is
clear of obstructions by using one of the following methods:
(a) For a well site, you must either:
(1) Drag a trawl over the site;
(2) Scan across the location using sonar equipment;

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

(3) Inspect the site using a diver;
(4) Videotape the site using a camera on a remotely operated vehicle (ROV); or
(5) Use another method approved by the District Manager if the particular site conditions warrant.
(b) For a platform or other facility site in water depths less than 300 feet, you must drag a trawl over the site.
(c) For a platform or other facility site in water depths 300 feet or more, you must either:
(1) Drag a trawl over the site;
(2) Scan across the site using sonar equipment; or
(3) Use another method approved by the Regional Supervisor if the particular site conditions warrant.
Back to Top

§250.1741   If I drag a trawl across a site, what requirements must I meet?
If you drag a trawl across the site in accordance with §250.1740, you must meet all of the requirements of this section.
(a) You must drag the trawl in a grid-like pattern as shown in the following table:
For a .  .  .
(1) Well site,
(2) Subsea well site,
(3) Platform site,
(4) Single-well caisson, well protector jacket, template, or
manifold,

You must drag the trawl across a .  .  .
300-foot-radius circle centered on the well location.
600-foot-radius circle centered on the well location.
1,320-foot-radius circle centered on the location of the
platform.
600-foot-radius circle centered on the structure location.

(b) You must trawl 100 percent of the limits described in paragraph (a) of this section in two directions.
(c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you
complete the site clearance procedures.
(d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing
position accuracy of ±30 feet.
(e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a
net strength equal or greater than that provided by No. 18 twine).
(f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological
feature.
(g) If you trawl near an active pipeline, you must meet the requirements in the following table:
For .  .  .
(1) Buried active pipelines,

You must trawl .  .  . And you must .  .  .
First contact the pipeline owner or operator to
determine the condition of the pipeline before
trawling over the buried pipeline.
(2) Unburied active pipelines that are 8 inches in no closer than 100
Trawl parallel to the pipeline Do not trawl across
diameter or larger,
feet to the either side the pipeline.
of the pipeline,
(3) Unburied smaller diameter active pipelines in no closer than 100
Trawl parallel to the pipeline. Do not trawl across
the trawl area that have obstructions (e.g.,
feet to either side of the pipeline.
pipeline valves) present,
the pipeline,
(4) Unburied active pipelines in the trawl area
parallel to the
that are smaller than 8 inches in diameter and pipeline,
have no obstructions present,
(h) You must ensure that any trawling contractor you may use:
(1) Has no corporate or other financial ties to you; and
(2) Has a valid commercial trawling license for both the vessel and its captain.
Back to Top

§250.1742   What other methods can I use to verify that a site is clear?
If you do not trawl a site, you can verify that the site is clear of obstructions by using any of the methods shown in the
following table:

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

If you use .  .  .
(a) Sonar,
(b) A diver,

(c) An ROV
(remotely
operated
vehicle),

You must .  .  .
cover 100 percent of the appropriate grid area
listed in §250.1741(a),
ensure that the diver visually inspects 100 percent
of the appropriate grid area listed in §250.1741(a),

And you must .  .  .
Use a sonar signal with a frequency of at least 500
kHz.
Ensure that the diver uses a search pattern of
concentric circles or parallel lines spaced no more
than 10 feet apart.
ensure that the ROV camera records videotape
Ensure that the ROV uses a pattern of concentric
over 100 percent of the appropriate grid area listed circles or parallel lines spaced no more than 10
in §250.1741(a),
feet apart.

Back to Top

§250.1743   How do I certify that a site is clear of obstructions?
(a) For a well site, you must submit to the appropriate District Manager within 30 days after you complete the
verification activities a form BSEE-0124, Application for Permit to Modify, to include the following information:
(1) A signed certification that the well site area is cleared of all obstructions;
(2) The date the verification work was performed and the vessel used;
(3) The extent of the area surveyed;
(4) The survey method used;
(5) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no
objects were recovered; and
(6) A post-trawling job plot or map showing the trawled area.
(b) For a platform or other facility site, you must submit the following information to the appropriate Regional
Supervisor within 30 days after you complete the verification activities:
(1) A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of
all obstructions and that a company representative witnessed the verification activities;
(2) A letter signed by an authorized official of the company that performed the verification work for you certifying that it
cleared the platform or other facility site area of all obstructions;
(3) The date the verification work was performed and the vessel used;
(4) The extent of the area surveyed;
(5) The survey method used;
(6) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no
objects were recovered; and
(7) A post-trawling job plot or map showing the trawled area.
Back to Top

PipElinE DEcommissioning
Back to Top

§250.1750   When may I decommission a pipeline in place?
You may decommission a pipeline in place when the Regional Supervisor determines that the pipeline does not
constitute a hazard (obstruction) to navigation and commercial fishing operations, unduly interfere with other uses of the
OCS, or have adverse environmental effects.
Back to Top

§250.1751   How do I decommission a pipeline in place?
You must do the following to decommission a pipeline in place:
(a) Submit a pipeline decommissioning application in triplicate to the Regional Supervisor for approval. Your
application must be accompanied by payment of the service fee listed in §250.125. Your application must include the
following information:

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

(1) Reason for the operation;
(2) Proposed decommissioning procedures;
(3) Length (feet) of segment to be decommissioned; and
(4) Length (feet) of segment remaining.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical;
(c) Flush the pipeline;
(d) Fill the pipeline with seawater;
(e) Cut and plug each end of the pipeline;
(f) Bury each end of the pipeline at least 3 feet below the seafloor or cover each end with protective concrete mats, if
required by the Regional Supervisor; and
(g) Remove all pipeline valves and other fittings that could unduly interfere with other uses of the OCS.
Back to Top

§250.1752   How do I remove a pipeline?
Before removing a pipeline, you must:
(a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval. Your application must
be accompanied by payment of the service fee listed in §250.125. Your application must include the following information:
(1) Proposed removal procedures;
(2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you will use to
remove the pipeline;
(3) Length (feet) to be removed;
(4) Length (feet) of the segment that will remain in place;
(5) Plans for transportation of the removed pipe for disposal or salvage;
(6) Plans to protect archaeological and sensitive biological features during removal operations, including a brief
assessment of the environmental impacts of the removal operations and procedures and mitigation measures that you will
take to minimize such impacts; and
(7) Projected removal schedule and duration.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and
(c) Flush the pipeline.
Back to Top

§250.1753   After I decommission a pipeline, what information must I submit?
Within 30 days after you decommission a pipeline, you must submit a written report to the Regional Supervisor that
includes the following:
(a) A summary of the decommissioning operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the pipeline was decommissioned
according to the approved application.
Back to Top

§250.1754   When must I remove a pipeline decommissioned in place?
You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is an
obstruction.
Back to Top

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]

eCFR — Code of Federal Regulations

Need assistance?
732 North Capitol Street, NW, Washington, DC 20401-0001     202.512.1800

Privacy  
|  
Important Links  
|  
Accessibility  
|  
Sitemap  
|  
COOP

http://www.ecfr.gov/cgi-bin/text-idx?SID=16db99b88fc6dc70a82be4dd1d6d80a2&mc=true&node=sp30.2.250.q&rgn=div6[8/19/2016 9:05:45 AM]