eCFR 30 CFR 250, Subpart D

ELECTRONIC CODE OF FEDERAL REGULATIONS
e-CFR data is current as of February 21, 2017
Title 30 → Chapter II → Subchapter B → Part 250 → Subpart D

Title 30: Mineral Resources
PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER CONTINENTAL SHELF

Subpart D—Oil and Gas Drilling Operations
Contents
GENERAL REQUIREMENTS
§250.400 General requirements.
§§250.401-250.403 [Reserved]
§250.404 What are the requirements for the crown block?
§250.405 What are the safety requirements for diesel engines used on a drilling rig?
§250.406 [Reserved]
§250.407 What tests must I conduct to determine reservoir characteristics?
§250.408 May I use alternative procedures or equipment during drilling operations?
§250.409 May I obtain departures from these drilling requirements?

APPLYING FOR A PERMIT TO DRILL
§250.410
§250.411
§250.412
§250.413
§250.414
§250.415
§250.416
§250.417
§250.418

How do I obtain approval to drill a well?
What information must I submit with my application?
What requirements must the location plat meet?
What must my description of well drilling design criteria address?
What must my drilling prognosis include?
What must my casing and cementing programs include?
What must I include in the diverter description?
[Reserved]
What additional information must I submit with my APD?

CASING AND CEMENTING REQUIREMENTS
§250.420 What well casing and cementing requirements must I meet?
§250.421 What are the casing and cementing requirements by type of casing string?
§250.422 When may I resume drilling after cementing?
§250.423 What are the requirements for casing and liner installation?
§§250.424-250.426 [Reserved]
§250.427 What are the requirements for pressure integrity tests?
§250.428 What must I do in certain cementing and casing situations?

DIVERTER SYSTEM REQUIREMENTS
§250.430
§250.431
§250.432
§250.433
§250.434

When must I install a diverter system?
What are the diverter design and installation requirements?
How do I obtain a departure to diverter design and installation requirements?
What are the diverter actuation and testing requirements?
What are the recordkeeping requirements for diverter actuations and tests?

§§250.440--250.451 [Reserved]
§250.452 What are the real-time monitoring requirements for Arctic OCS exploratory drilling operations?

DRILLING FLUID REQUIREMENTS
§250.455
§250.456
§250.457
§250.458
§250.459

What are the general requirements for a drilling fluid program?
What safe practices must the drilling fluid program follow?
What equipment is required to monitor drilling fluids?
What quantities of drilling fluids are required?
What are the safety requirements for drilling fluid-handling areas?

OTHER DRILLING REQUIREMENTS
§250.460
§250.461
§250.462
§250.463

What are the requirements for conducting a well test?
What are the requirements for directional and inclination surveys?
What are the source control, containment, and collocated equipment requirements?
Who establishes field drilling rules?

APPLYING FOR A PERMIT TO MODIFY AND W ELL RECORDS
§250.465 When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to BSEE?
§§250.466--250.469 [Reserved]

ADDITIONAL ARCTIC OCS REQUIREMENTS
§250.470
§250.471
§250.472
§250.473

What additional information must I submit with my APD for Arctic OCS exploratory drilling operations?
What are the requirements for Arctic OCS source control and containment?
What are the relief rig requirements for the Arctic OCS?
What must I do to protect health, safety, property, and the environment while operating on the Arctic OCS?

HYDROGEN SULFIDE
§250.490 Hydrogen sulfide.

GENERAL REQUIREMENTS
§250.400 General requirements.
Drilling operations must be conducted in a safe manner to protect against harm or damage to life
(including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS),
including any mineral deposits (in areas leased and not leased), the National security or defense, or the
marine, coastal, or human environment. In addition to the requirements of this subpart, you must also
follow the applicable requirements of subpart G of this part.
[81 FR 26017, Apr. 29, 2016]

§§250.401-250.403 [Reserved]
§250.404 What are the requirements for the crown block?
You must have a crown block safety device that prevents the traveling block from striking the crown
block. You must check the device for proper operation at least once per week and after each drill-line
slipping operation and record the results of this operational check in the driller's report.
§250.405 What are the safety requirements for diesel engines used on a drilling rig?

You must equip each diesel engine with an air intake device to shut down the diesel engine in the
event of a runaway.
(a) For a diesel engine that is not continuously manned, you must equip the engine with an
automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip the engine with either an
automatic or remote manual air intake shutdown device;
(c) You do not have to equip a diesel engine with an air intake device if it meets one of the following
criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 36149, June 6, 2016]

§250.406 [Reserved]
§250.407 What tests must I conduct to determine reservoir characteristics?
You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas,
sulphur, and water in the formations penetrated by logging, formation sampling, or well testing.
§250.408 May I use alternative procedures or equipment during drilling operations?
You may use alternative procedures or equipment during drilling operations after receiving approval
from the District Manager. You must identify and discuss your proposed alternative procedures or
equipment in your Application for Permit to Drill (APD) (Form BSEE-0123) (see §250.414(h)). Procedures
for obtaining approval are described in §250.141 of this part.
§250.409 May I obtain departures from these drilling requirements?
The District Manager may approve departures from the drilling requirements specified in this
subpart. You may apply for a departure from drilling requirements by writing to the District Manager. You
should identify and discuss the departure you are requesting in your APD (see §250.414(h)).

APPLYING FOR A PERMIT TO DRILL
§250.410 How do I obtain approval to drill a well?
You must obtain written approval from the District Manager before you begin drilling any well or

before you sidetrack, bypass, or deepen a well. To obtain approval, you must:
(a) Submit the information required by §§250.411 through 250.418;
(b) Include the well in your approved Exploration Plan (EP), Development and Production Plan
(DPP), or Development Operations Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30
CFR part 553; and
(d) Submit the following to the District Manager:
(1) An original and two complete copies of Form BSEE-0123, Application for Permit to Drill (APD),
and Form BSEE-0123S, Supplemental APD Information Sheet;
(2) A separate public information copy of forms BSEE-0123 and BSEE-0123S that meets the
requirements of §250.186; and
(3) Payment of the service fee listed in §250.125.
§250.411 What information must I submit with my application?
In addition to forms BSEE-0123 and BSEE-0123S, you must include the information required in this
subpart and subpart G of this part, including the following:
Information that you must include with an APD

Where to find a description

(a) Plat that shows locations of the proposed well,

§250.412.

(b) Design criteria used for the proposed well,

§250.413.

(c) Drilling prognosis,

§250.414.

(d) Casing and cementing programs,

§250.415.

(e) Diverter systems descriptions,

§250.416.

(f) BOP system descriptions,

§250.731.

(g) Requirements for using a MODU, and

§250.713.

(h) Additional information.

§250.418.

[81 FR 26017, Apr. 29, 2016]

§250.412 What requirements must the location plat meet?
The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well in feet or meters from the block
line;
(d) Contain the longitude and latitude coordinates, and either Universal Transverse Mercator gridsystem coordinates or state plane coordinates in the Lambert or Transverse Mercator Projection system

for the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum is North American Datum 27 or
83) for these coordinates. If the datum was converted, you must state the method used for this
conversion, since the various methods may produce different values.
§250.413 What must my description of well drilling design criteria address?
Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section, maximum anticipated surface
pressures are the pressures that you reasonably expect to be exerted upon a casing string and its
related wellhead equipment. In calculating maximum anticipated surface pressures, you must consider:
drilling, completion, and producing conditions; drilling fluid densities to be used below various casing
strings; fracture gradients of the exposed formations; casing setting depths; total well depth; formation
fluid types; safety margins; and other pertinent conditions. You must include the calculations used to
determine the pressures for the drilling and the completion phases, including the anticipated surface
pressure used for designing the production string;
(g) A single plot containing curves for estimated pore pressures, formation fracture gradients,
proposed drilling fluid weights, planned safe drilling margin, and casing setting depths in true vertical
measurements;
(h) A summary report of the shallow hazards site survey that describes the geological and
manmade conditions if not previously submitted; and
(i) Permafrost zones, if applicable.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

§250.414 What must my drilling prognosis include?
Your drilling prognosis must include a brief description of the procedures you will follow in drilling
the well. This prognosis includes but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin that is between the estimated pore pressure and the lesser of
estimated fracture gradients or casing shoe pressure integrity test and that is based on a risk
assessment consistent with expected well conditions and operations.
(1) Your safe drilling margin must also include use of equivalent downhole mud weight that is:

(i) Greater than the estimated pore pressure; and
(ii) Except as provided in paragraph (c)(2) of this section, a minimum of 0.5 pound per gallon below
the lower of the casing shoe pressure integrity test or the lowest estimated fracture gradient.
(2) In lieu of meeting the criteria in paragraph (c)(1)(ii) of this section, you may use an equivalent
downhole mud weight as specified in your APD, provided that you submit adequate documentation (such
as risk modeling data, off-set well data, analog data, seismic data) to justify the alternative equivalent
downhole mud weight.
(3) When determining the pore pressure and lowest estimated fracture gradient for a specific
interval, you must consider related off-set well behavior observations.
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones containing fresh water, oil, gas, or
abnormally pressured formation fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternate procedures or departures from the
requirements of this subpart in one place in the APD. You must explain how the alternate procedures
afford an equal or greater degree of protection, safety, or performance, or why the departures are
requested;
(i) Projected plans for well testing (refer to §250.460);
(j) The type of wellhead system and liner hanger system to be installed and a descriptive schematic,
which includes but is not limited to pressure ratings, dimensions, valves, load shoulders, and locking
mechanisms, if applicable; and
(k) Any additional information required by the District Manager needed to clarify or evaluate your
drilling prognosis.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26017, Apr. 29, 2016]

§250.415 What must my casing and cementing programs include?
Your casing and cementing programs must include:
(a) The following well design information:
(1) Hole sizes;
(2) Bit depths (including measured and true vertical depth (TVD));
(3) Casing information, including sizes, weights, grades, collapse and burst values, types of
connection, and setting depths (measured and TVD) for all sections of each casing interval; and
(4) Locations of any installed rupture disks (indicate if burst or collapse and rating);
(b) Casing design safety factors for tension, collapse, and burst with the assumptions made to
arrive at these values;

(c) Type and amount of cement (in cubic feet) planned for each casing string;
(d) In areas containing permafrost, setting depths for conductor and surface casing based on the
anticipated depth of the permafrost. Your program must provide protection from thaw subsidence and
freezeback effect, proper anchorage, and well control;
(e) A statement of how you evaluated the best practices included in API RP 65, Recommended
Practice for Cementing Shallow Water Flow Zones in Deep Water Wells (as incorporated by reference in
§250.198), if you drill a well in water depths greater than 500 feet and are in either of the following two
areas:
(1) An “area with an unknown shallow water flow potential” is a zone or geologic formation where
neither the presence nor absence of potential for a shallow water flow has been confirmed.
(2) An “area known to contain a shallow water flow hazard” is a zone or geologic formation for
which drilling has confirmed the presence of shallow water flow; and
(f) A written description of how you evaluated the best practices included in API Standard 65—Part
2, Isolating Potential Flow Zones During Well Construction, Second Edition (as incorporated by reference
in §250.198). Your written description must identify the mechanical barriers and cementing practices you
will use for each casing string (reference API Standard 65—Part 2, Sections 4 and 5).
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50891, Aug. 22, 2012; 81 FR 26018, Apr. 29, 2016]

§250.416 What must I include in the diverter description?
You must include in the diverter description:
(a) A description of the diverter system and its operating procedures;
(b) A schematic drawing of the diverter system (plan and elevation views) that shows:
(1) The size of the element installed in the diverter housing;
(2) Spool outlet internal diameter(s);
(3) Diverter-line lengths and diameters; burst strengths and radius of curvature at each turn; and
(4) Valve type, size, working pressure rating, and location.
[81 FR 26018, Apr. 29, 2016]

§250.417 [Reserved]
§250.418 What additional information must I submit with my APD?
You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling equipment, if not already on file with the
appropriate District office;
(b) A drilling fluids program that includes the minimum quantities of drilling fluids and drilling fluid
materials, including weight materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally drilled;

(d) A Hydrogen Sulfide Contingency Plan (see §250.490), if applicable, and not previously
submitted;
(e) A welding plan (see §§250.109 to 250.113) if not previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the drilling equipment, BOP systems
and components, diverter systems, and other associated equipment and materials are suitable for
operating under such conditions;
(g) A request for approval, if you plan to wash out or displace cement to facilitate casing removal
upon well abandonment. Your request must include a description of how far below the mudline you
propose to displace cement and how you will visually monitor returns;
(h) Certification of your casing and cementing program as required in §250.420(a)(7); and
(i) Such other information as the District Manager may require.
(j) For Arctic OCS exploratory drilling operations, you must provide the information required by
§250.470.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 81 FR 26018, Apr. 29, 2016; 81 FR
46561, July 15, 2016]

CASING AND CEMENTING REQUIREMENTS
§250.420 What well casing and cementing requirements must I meet?
You must case and cement all wells. Your casing and cementing programs must meet the
applicable requirements of this subpart and of subpart G of this part.
(a) Casing and cementing program requirements. Your casing and cementing programs must:
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any stratum through the wellbore into
offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing strata;
(4) Protect freshwater aquifers from contamination;
(5) Support unconsolidated sediments;
(6) Provide adequate centralization to ensure proper cementation; and
(7)(i) Include a certification signed by a registered professional engineer that the casing and
cementing design is appropriate for the purpose for which it is intended under expected wellbore
conditions, and is sufficient to satisfy the tests and requirements of this section and §250.423. Submit
this certification with your APD (Form BSEE-0123).
(ii) You must have the registered professional engineer involved in the casing and cementing
design process.
(iii) The registered professional engineer must be registered in a state of the United States and
have sufficient expertise and experience to perform the certification.

(b) Casing requirements. (1) You must design casing (including liners) to withstand the anticipated
stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal
effects; and combinations thereof.
(2) The casing design must include safety measures that ensure well control during drilling and safe
operations during the life of the well.
(3) On all wells that use subsea BOP stacks, you must include two independent barriers, including
one mechanical barrier, in each annular flow path (examples of barriers include, but are not limited to,
primary cement job and seal assembly). For the final casing string (or liner if it is your final string), you
must install one mechanical barrier in addition to cement to prevent flow in the event of a failure in the
cement. A dual float valve, by itself, is not considered a mechanical barrier. These barriers cannot be
modified prior to or during completion or abandonment operations. The BSEE District Manager may
approve alternative options under §250.141. You must submit documentation of this installation to BSEE
in the End-of-Operations Report (Form BSEE-0125).
(4) If you need to substitute a different size, grade, or weight of casing than what was approved in
your APD, you must contact the District Manager for approval prior to installing the casing.
(c) Cementing requirements. (1) You must design and conduct your cementing jobs so that cement
composition, placement techniques, and waiting times ensure that the cement placed behind the bottom
500 feet of casing attains a minimum compressive strength of 500 psi before drilling out the casing or
before commencing completion operations. (If a liner is used refer to §250.421(f)).
(2) You must use a weighted fluid during displacement to maintain an overbalanced hydrostatic
pressure during the cement setting time, except when cementing casings or liners in riserless hole
sections.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 81 FR 26018, Apr. 29, 2016]

§250.421 What are the casing and cementing requirements by type of casing string?
The table in this section identifies specific design, setting, and cementing requirements for casing
strings and liners. For the purposes of subpart D, the casing strings in order of normal installation are as
follows: drive or structural, conductor, surface, intermediate, and production casings (including liners).
The District Manager may approve or prescribe other casing and cementing requirements where
appropriate.
Casing type Casing requirements

Cementing requirements

(a) Drive or
Structural

Set by driving, jetting, or drilling to the If you drilled a portion of this hole, you must use
minimum depth as approved or
enough cement to fill the annular space back to the
prescribed by the District Manager
mudline.

(b)
Conductor

Design casing and select setting
depths based on relevant engineering
and geologic factors. These factors
include the presence or absence of
hydrocarbons, potential hazards, and
water depths
Set casing immediately before drilling
into formations known to contain oil or
gas. If you encounter oil or gas or
unexpected formation pressure before
the planned casing point, you must set
casing immediately and set it above
the encountered zone

Use enough cement to fill the calculated annular
space back to the mudline.
Verify annular fill by observing cement returns. If
you cannot observe cement returns, use additional
cement to ensure fill-back to the mudline.
For drilling on an artificial island or when using a
well cellar, you must discuss the cement fill level
with the District Manager.

(c) Surface

Design casing and select setting

Use enough cement to fill the calculated annular

depths based on relevant engineering
and geologic factors. These factors
include the presence or absence of
hydrocarbons, potential hazards, and
water depths

space to at least 200 feet inside the conductor
casing.
When geologic conditions such as near-surface
fractures and faulting exist, you must use enough
cement to fill the calculated annular space to the
mudline.

(d)
Design casing and select setting depth
Intermediate based on anticipated or encountered
geologic characteristics or wellbore
conditions

Use enough cement to cover and isolate all
hydrocarbon-bearing zones and isolate abnormal
pressure intervals from normal pressure intervals
in the well.
As a minimum, you must cement the annular
space 500 feet above the casing shoe and 500
feet above each zone to be isolated.

(e)
Production

Design casing and select setting depth
based on anticipated or encountered
geologic characteristics or wellbore
conditions

Use enough cement to cover or isolate all
hydrocarbon-bearing zones above the shoe.
As a minimum, you must cement the annular
space at least 500 feet above the casing shoe and
500 feet above the uppermost hydrocarbonbearing zone.

(f) Liners

If you use a liner as surface casing,
Same as cementing requirements for specific
you must set the top of the liner at least casing types. For example, a liner used as
200 feet above the previous
intermediate casing must be cemented according
casing/liner shoe
to the cementing requirements for intermediate
If you use a liner as an intermediate
casing. If you have a liner lap and are unable to
string below a surface string or
cement 500 feet above the previous shoe, as
production casing below an
provided by paragraphs (d) and (e) of this section,
intermediate string, you must set the you must submit and receive approval from the
top of the liner at least 100 feet above District Manager on a case-by-case basis.
the previous casing shoe
You may not use a liner as conductor
casing
A subsea well casing string whose top
is above the mudline and that has been
cemented back to the mudline will not
be considered a liner

[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26018, Apr. 29, 2016]

§250.422 When may I resume drilling after cementing?
(a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling
after the cement has been held under pressure for 12 hours. For conductor casing, you may resume
drilling after the cement has been held under pressure for 8 hours. One acceptable method of holding
cement under pressure is to use float valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during the 8- or 12-hour waiting time, you
must determine, before nippling down, when it will be safe to do so. You must base your determination
on a knowledge of formation conditions, cement composition, effects of nippling down, presence of
potential drilling hazards, well conditions during drilling, cementing, and post cementing, as well as past
experience.
§250.423 What are the requirements for casing and liner installation?
You must ensure proper installation of casing in the subsea wellhead or liner in the liner hanger.
(a) You must ensure that the latching mechanisms or lock down mechanisms are engaged upon
successfully installing and cementing the casing string. If there is an indication of an inadequate cement

job, you must comply with §250.428(c).
(b) If you run a liner that has a latching mechanism or lock down mechanism, you must ensure that
the latching mechanisms or lock down mechanisms are engaged upon successfully installing and
cementing the liner. If there is an indication of an inadequate cement job, you must comply with
§250.428(c).
(c) You must perform a pressure test on the casing seal assembly to ensure proper installation of
casing or liner. You must perform this test for the intermediate and production casing strings or liners.
(1) You must submit for approval with your APD, test procedures and criteria for a successful test.
(2) You must document all your test results and make them available to BSEE upon request.
[81 FR 26019, Apr. 29, 2016]

§§250.424-250.426 [Reserved]
§250.427 What are the requirements for pressure integrity tests?
You must conduct a pressure integrity test below the surface casing or liner and all intermediate
casings or liners. The District Manager may require you to run a pressure-integrity test at the conductor
casing shoe if warranted by local geologic conditions or the planned casing setting depth. You must
conduct each pressure integrity test after drilling at least 10 feet but no more than 50 feet of new hole
below the casing shoe. You must test to either the formation leak-off pressure or to an equivalent drilling
fluid weight if identified in an approved APD.
(a) You must use the pressure integrity test and related hole-behavior observations, such as porepressure test results, gas-cut drilling fluid, and well kicks to adjust the drilling fluid program and the
setting depth of the next casing string. You must record all test results and hole-behavior observations
made during the course of drilling related to formation integrity and pore pressure in the driller's report.
(b) While drilling, you must maintain the safe drilling margins identified in §250.414. When you
cannot maintain the safe margins, you must suspend drilling operations and remedy the situation.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26019, Apr. 29, 2016]

§250.428 What must I do in certain cementing and casing situations?
The table in this section describes actions that lessees must take when certain situations occur
during casing and cementing activities.
If you encounter the following situation: Then you must . . .
(a) Have unexpected formation pressures or Submit a revised casing program to the District Manager for
conditions that warrant revising your casing approval.
design,
(b) Need to change casing setting depths or Submit those changes to the District Manager for approval
hole interval drilling depth (for a BHA with an and include a certification by a professional engineer (PE)
under-reamer, this means bit depth) more that he or she reviewed and approved the proposed
than 100 feet true vertical depth (TVD) from changes.
the approved APD due to conditions
encountered during drilling operations,
(c) Have indication of inadequate cement
(1) Locate the top of cement by:
job (such as lost returns, no cement returns (i) Running a temperature survey;
to mudline or expected height, cement
(ii) Running a cement evaluation log; or

channeling, or failure of equipment),

(iii) Using a combination of these techniques.
(2) Determine if your cement job is inadequate. If your
cement job is determined to be inadequate, refer to
paragraph (d) of this section.
(3) If your cement job is determined to be adequate, report
the results to the District Manager in your submitted WAR.

(d) Inadequate cement job,

Take remedial actions. The District Manager must review
and approve all remedial actions before you may take
them, unless immediate actions must be taken to ensure
the safety of the crew or to prevent a well-control event. If
you complete any immediate action to ensure the safety of
the crew or to prevent a well-control event, submit a
description of the action to the District Manager when that
action is complete. Any changes to the well program will
require submittal of a certification by a professional
engineer (PE) certifying that he or she reviewed and
approved the proposed changes, and must meet any other
requirements of the District Manager.

(e) Primary cement job that did not isolate
abnormal pressure intervals,

Isolate those intervals from normal pressures by squeeze
cementing before you complete; suspend operations; or
abandon the well, whichever occurs first.

(f) Decide to produce a well that was not
originally contemplated for production,

Have at least two cemented casing strings (does not
include liners) in the well. Note: All producing wells must
have at least two cemented casing strings.

(g) Want to drill a well without setting
conductor casing,

Submit geologic data and information to the District
Manager that demonstrates the absence of shallow
hydrocarbons or hazards. This information must include
logging and drilling fluid-monitoring from wells previously
drilled within 500 feet of the proposed well path down to the
next casing point.

(h) Need to use less than required cement Submit information to the District Manager that
for the surface casing during floating drilling demonstrates the use of less cement is necessary.
operations to provide protection from burst
and collapse pressures,
(i) Cement across a permafrost zone,

Use cement that sets before it freezes and has a low heat
of hydration.

(j) Leave the annulus opposite a permafrost Fill the annulus with a liquid that has a freezing point below
zone uncemented,
the minimum permafrost temperature and minimizes
opposite a corrosion.
(k) Plan to use a valve(s) on the drive pipe
during cementing operations for the
conductor casing, surface casing, or liner,

Include a description of the plan in your APD. Your
description must include a schematic of the valve and
height above the water line. The valve must be remotely
operated and full opening with visual observation while
taking returns. The person in charge of observing returns
must be in communication with the drill floor. You must
record in your daily report and in the WAR if cement returns
were observed. If cement returns are not observed, you
must contact the District Manager and obtain approval of
proposed plans to locate the top of cement before
continuing with operations.

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012; 81 FR 26019, Apr. 29, 2016]

DIVERTER SYSTEM REQUIREMENTS

§250.430 When must I install a diverter system?
You must install a diverter system before you drill a conductor or surface hole. The diverter system
consists of a diverter sealing element, diverter lines, and control systems. You must design, install, use,
maintain, and test the diverter system to ensure proper diversion of gases, water, drilling fluid, and other
materials away from facilities and personnel.
§250.431 What are the diverter design and installation requirements?
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches
for surface wellhead configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind diversion capability;
(c) Use at least two diverter control stations. One station must be on the drilling floor. The other
station must be in a readily accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All valves in the diverter system must be
full-opening. You may not install manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed for each line for bottom-founded
drilling units) in the diverter lines, maximize the radius of curvature of turns, and target all right angles
and sharp turns;
(f) Anchor and support the entire diverter system to prevent whipping and vibration; and
(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling
objects.
§250.432 How do I obtain a departure to diverter design and installation requirements?
The table below describes possible departures from the diverter requirements and the conditions
required for each departure. To obtain one of these departures, you must have discussed the departure
in your APD and received approval from the District Manager.
If you want a departure to:

Then you must . . .

(a) Use flexible hose for diverter lines instead Use flexible hose that has integral end couplings.
of rigid pipe,
(b) Use only one spool outlet for your diverter (1) Have branch lines that meet the minimum internal
system,
diameter requirements; and (2) Provide downwind
diversion capability.
(c) Use a spool with an outlet with an internal Use a spool that has dual outlets with an internal
diameter of less than 10 inches on a surface diameter of at least 8 inches.
wellhead,
(d) Use a single diverter line for floating drilling Maintain an appropriate vessel heading to provide for
operations on a dynamically positioned
downwind diversion.
drillship,
§250.433 What are the diverter actuation and testing requirements?
When you install the diverter system, you must actuate the diverter sealing element, diverter valves,
and diverter-control systems and control stations. You must also flow-test the vent lines.

(a) For drilling operations with a surface wellhead configuration, you must actuate the diverter
system at least once every 24-hour period after the initial test. After you have nippled up on conductor
casing, you must pressure-test the diverter-sealing element and diverter valves to a minimum of 200 psi.
While the diverter is installed, you must conduct subsequent pressure tests within 7 days after the
previous test.
(b) For floating drilling operations with a subsea BOP stack, you must actuate the diverter system
within 7 days after the previous actuation.
(c) You must alternate actuations and tests between control stations.
§250.434 What are the recordkeeping requirements for diverter actuations and tests?
You must record the time, date, and results of all diverter actuations and tests in the driller's report.
In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the pressure test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing or actuations and record actions
taken to remedy the problems or irregularities; and
(e) Retain all pressure charts and reports pertaining to the diverter tests and actuations at the
facility for the duration of drilling the well.
§§250.440--250.451 [Reserved]
§250.452 What are the real-time monitoring requirements for Arctic OCS exploratory drilling
operations?
(a) When conducting exploratory drilling operations on the Arctic OCS, you must gather and monitor
real-time data using an independent, automatic, and continuous monitoring system capable of recording,
storing, and transmitting data regarding the following:
(1) The BOP control system;
(2) The well's fluid handling systems on the rig; and
(3) The well's downhole conditions as monitored by a downhole sensing system, when such a
system is installed.
(b) During well operations, you must transmit the data identified in paragraph (a) of this section as
they are gathered, barring unforeseeable or unpreventable interruptions in transmission, and have the
capability to monitor the data onshore, using qualified personnel. Onshore personnel who monitor realtime data must have the capability to contact rig personnel during operations. After well operations, you
must store the data at a designated location for recordkeeping purposes as required in §§250.740 and
250.741. You must provide BSEE with access to your real-time monitoring data onshore upon request.
[81 FR 46561, July 15, 2016]

DRILLING FLUID REQUIREMENTS
§250.455 What are the general requirements for a drilling fluid program?

You must design and implement your drilling fluid program to prevent the loss of well control. This
program must address drilling fluid safe practices, testing and monitoring equipment, drilling fluid
quantities, and drilling fluid-handling areas.
§250.456 What safe practices must the drilling fluid program follow?
Your drilling fluid program must include the following safe practices:
(a) Before starting out of the hole with drill pipe, you must properly condition the drilling fluid. You
must circulate a volume of drilling fluid equal to the annular volume with the drill pipe just off-bottom. You
may omit this practice if documentation in the driller's report shows:
(1) No indication of formation fluid influx before starting to pull the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per gallon (1.5 pounds per cubic foot) of
the drilling fluid entering the hole; and
(3) Other drilling fluid properties are within the limits established by the program approved in the
APD.
(b) Record each time you circulate drilling fluid in the hole in the driller's report;
(c) When coming out of the hole with drill pipe, you must fill the annulus with drilling fluid before the
hydrostatic pressure decreases by 75 psi, or every five stands of drill pipe, whichever gives a lower
decrease in hydrostatic pressure. You must calculate the number of stands of drill pipe and drill collars
that you may pull before you must fill the hole. You must also calculate the equivalent drilling fluid volume
needed to fill the hole. Both sets of numbers must be posted near the driller's station. You must use a
mechanical, volumetric, or electronic device to measure the drilling fluid required to fill the hole;
(d) You must run and pull drill pipe and downhole tools at controlled rates so you do not swab or
surge the well;
(e) When there is an indication of swabbing or influx of formation fluids, you must take appropriate
measures to control the well. You must circulate and condition the well, on or near-bottom, unless well or
drilling-fluid conditions prevent running the drill pipe back to the bottom;
(f) You must calculate and post near the driller's console the maximum pressures that you may
safely contain under a shut-in BOP for each casing string. The pressures posted must consider the
surface pressure at which the formation at the shoe would break down, the rated working pressure of the
BOP stack, and 70 percent of casing burst (or casing test as approved by the District Manager). As a
minimum, you must post the following two pressures:
(1) The surface pressure at which the shoe would break down. This calculation must consider the
current drilling fluid weight in the hole; and
(2) The lesser of the BOP's rated working pressure or 70 percent of casing-burst pressure (or
casing test otherwise approved by the District Manager);
(g) You must install an operable drilling fluid-gas separator and degasser before you begin drilling
operations. You must maintain this equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must circulate or reverse-circulate the test
fluids in the hole. If circulating out test fluids is not feasible, you may bullhead test fluids out of the drillstem test string and tools with an appropriate kill weight fluid;
(i) When circulating, you must test the drilling fluid at least once each tour, or more frequently if

conditions warrant. Your tests must conform to industry-accepted practices and include density, viscosity,
and gel strength; hydrogenion concentration; filtration; and any other tests the District Manager requires
for monitoring and maintaining drilling fluid quality, prevention of downhole equipment problems and for
kick detection. You must record the results of these tests in the drilling fluid report; and
(j) In areas where permafrost and/or hydrate zones are present or may be present, you must control
drilling fluid temperatures to drill safely through those zones.
[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012; 81 FR 26020, Apr. 29, 2016]

§250.457 What equipment is required to monitor drilling fluids?
Once you establish drilling fluid returns, you must install and maintain the following drilling fluidsystem monitoring equipment throughout subsequent drilling operations. This equipment must have the
following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume gains and losses. This indicator must
include both a visual and an audible warning device;
(b) Volume measuring device to accurately determine drilling fluid volumes required to fill the hole
on trips;
(c) Return indicator devices that indicate the relationship between drilling fluid-return flow rate and
pump discharge rate. This indicator must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns. The indicator may be located in the
drilling fluid-logging compartment or on the rig floor. If the indicators are only in the logging compartment,
you must continually man the equipment and have a means of immediate communication with the rig
floor. If the indicators are on the rig floor only, you must install an audible alarm.
§250.458 What quantities of drilling fluids are required?
(a) You must use, maintain, and replenish quantities of drilling fluid and drilling fluid materials at the
drill site as necessary to ensure well control. You must determine those quantities based on known or
anticipated drilling conditions, rig storage capacity, weather conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and drilling fluid materials, including weight
materials and additives in the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and drilling fluid material to maintain well
control, you must suspend drilling operations.
§250.459 What are the safety requirements for drilling fluid-handling areas?
You must classify drilling fluid-handling areas according to API RP 500, Recommended Practice for
Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class I,
Division 1 and Division 2 (as incorporated by reference in §250.198); or API RP 505, Recommended
Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as
Class 1, Zone 0, Zone 1, and Zone 2 (as incorporated by reference in §250.198). In areas where
dangerous concentrations of combustible gas may accumulate, you must install and maintain a
ventilation system and gas monitors. Drilling fluid-handling areas must have the following safety
equipment:
(a) A ventilation system capable of replacing the air once every 5 minutes or 1.0 cubic feet of airvolume flow per minute, per square foot of area, whichever is greater. In addition:
(1) If natural means provide adequate ventilation, then a mechanical ventilation system is not

necessary;
(2) If a mechanical system does not run continuously, then it must activate when gas detectors
indicate the presence of 1 percent or more of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be hazardous, then you must maintain
the drilling fluid-handling area at a negative pressure. You must protect the negative pressure area by
using at least one of the following: a pressure-sensitive alarm, open-door alarms on each access to the
area, automatic door-closing devices, air locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate ventilation is provided by
natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse
between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases.
Where you use air for pressuring equipment, you must locate the air intake outside of and as far as
practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system fails.

OTHER DRILLING REQUIREMENTS
§250.460 What are the requirements for conducting a well test?
(a) If you intend to conduct a well test, you must include your projected plans for the test with your
APD (form BSEE-0123) or in an Application for Permit to Modify (APM) (form BSEE-0124). Your plans
must include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice before starting a well test.
§250.461 What are the requirements for directional and inclination surveys?
For this subpart, BSEE classifies a well as vertical if the calculated average of inclination readings
does not exceed 3 degrees from the vertical.
(a) Survey requirements for a vertical well. (1) You must conduct inclination surveys on each
vertical well and record the results. Survey intervals may not exceed 1,000 feet during the normal course
of drilling;
(2) You must also conduct a directional survey that provides both inclination and azimuth, and

digitally record the results in electronic format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b) Survey requirements for directional well. You must conduct directional surveys on each
directional well and digitally record the results. Surveys must give both inclination and azimuth at
intervals not to exceed 500 feet during the normal course of drilling. Intervals during angle-changing
portions of the hole may not exceed 100 feet.
(c) Measurement while drilling. You may use measurement-while-drilling technology if it meets the
requirements of this section.
(d) Composite survey requirements. (1) Your composite directional survey must show the interval
from the bottom of the conductor casing to total depth. In the absence of conductor casing, the survey
must show the interval from the bottom of the drive or structural casing to total depth; and
(2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north
after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections
used and include a listing of the directionally computed inclinations and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to
furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the
adjoining leaseholder requests a copy of the survey for the protection of correlative rights.
§250.462 What are the source control, containment, and collocated equipment requirements?
For drilling operations using a subsea BOP or surface BOP on a floating facility, you must have the
ability to control or contain a blowout event at the sea floor.
(a) To determine your required source control and containment capabilities you must do the
following:
(1) Consider a scenario of the wellbore fully evacuated to reservoir fluids, with no restrictions in the
well.
(2) Evaluate the performance of the well as designed to determine if a full shut-in can be achieved
without having reservoir fluids broach to the sea floor. If your evaluation indicates that the well can only
be partially shut-in, then you must determine your ability to flow and capture the residual fluids to a
surface production and storage system.
(b) You must have access to and the ability to deploy Source Control and Containment Equipment
(SCCE) and all other necessary supporting and collocated equipment to regain control of the well. SCCE
means the capping stack, cap-and-flow system, containment dome, and/or other subsea and surface
devices, equipment, and vessels, which have the collective purpose to control a spill source and stop the
flow of fluids into the environment or to contain fluids escaping into the environment. This SCCE,
supporting equipment, and collocated equipment must include, but is not limited to, the following:
(1) Subsea containment and capture equipment, including containment domes and capping stacks;
(2) Subsea utility equipment including hydraulic power sources and hydrate control equipment;
(3) Collocated equipment including dispersant injection equipment;

(4) Riser systems;
(5) Remotely operated vehicles (ROVs);
(6) Capture vessels;
(7) Support vessels; and
(8) Storage facilities.
(c) You must submit a description of your source control and containment capabilities to the
Regional Supervisor and receive approval before BSEE will approve your APD, Form BSEE-0123. The
description of your containment capabilities must contain the following:
(1) Your source control and containment capabilities for controlling and containing a blowout event
at the seafloor;
(2) A discussion of the determination required in paragraph (a) of this section; and
(3) Information showing that you have access to and the ability to deploy all equipment required by
paragraph (b) of this section.
(d) You must contact the District Manager and Regional Supervisor for reevaluation of your source
control and containment capabilities if your:
(1) Well design changes; or
(2) Approved source control and containment equipment is out of service.
(e) You must maintain, test, and inspect the source control, containment, and collocated equipment
identified in the following table according to these requirements:
Equipment

Requirements, you must:

Additional information

(1) Capping
stacks,

(i) Function test all pressure containing
Pressure containing critical
critical components on a quarterly frequency components are those components that
(not to exceed 104 days between tests),
will experience wellbore pressure
during a shut-in after being functioned.
(ii) Pressure test pressure containing critical Pressure containing critical
components on a bi-annual basis, but not
components are those components that
later than 210 days from the last pressure
will experience wellbore pressure
test. All pressure testing must be witnessed during a shut-in. These components
by BSEE (if available) and a BSEE-approved include, but are not limited to: All blind
verification organization
rams, wellhead connectors, and outlet
valves.
(iii) Notify BSEE at least 21 days prior to
commencing any pressure testing

(2) Production
safety systems
used for flow and
capture
operations,

(i) Meet or exceed the requirements set forth
in §§250.800 through 250.808, excluding
required equipment that would be installed
below the wellhead or that is not applicable
to the cap and flow system.
(ii) Have all equipment unique to
containment operations available for
inspection at all times

(3) Subsea utility
equipment,

Have all referenced containment equipment Subsea utility equipment includes, but
available for inspection at all times
is not limited to: Hydraulic power
sources, debris removal, and hydrate
control equipment.

(4) Collocated
equipment,

Have equipment available for inspection at
all times

Collocated equipment includes, but is
not limited to, dispersant injection
equipment and other subsea control
equipment.

[81 FR 26020, Apr. 29, 2016]

§250.463 Who establishes field drilling rules?
(a) The District Manager may establish field drilling rules different from the requirements of this
subpart when geological and engineering information shows that specific operating requirements are
appropriate. You must comply with field drilling rules and nonconflicting requirements of this subpart. The
District Manager may amend or cancel field drilling rules at any time.
(b) You may request the District Manager to establish, amend, or cancel field drilling rules.

APPLYING FOR A PERMIT TO MODIFY AND WELL RECORDS
§250.465 When must I submit an Application for Permit to Modify (APM) or an End of Operations
Report to BSEE?
(a) You must submit an APM (form BSEE-0124) or an End of Operations Report (form BSEE-0125)
and other materials to the Regional Supervisor as shown in the following table. You must also submit a
public information copy of each form.
When you . . .

Then you must . . .

(1) Intend to revise
your drilling plan,
change major drilling
equipment, or
plugback,

Submit form BSEE-0124 Receive written or oral approval from the District
or request oral approval, Manager before you begin the intended operation. If you
get an approval, you must submit form BSEE-0124 no
later than the end of the 3rd business day following the
oral approval. In all cases, or you must meet the
additional requirements in paragraph (b) of this section.

(2) Determine a well's Immediately Submit a
final surface location, form BSEE-0124,
water depth, and the
rotary kelly bushing
elevation,

And . . .

Submit a plat certified by a registered land surveyor that
meets the requirements of §250.412.

(3) Move a drilling unit Submit forms BSEESubmit appropriate copies of the well records.
from a wellbore before 0124 and BSEE-0125
completing a well,
within 30 days after the
suspension of wellbore
operations,
(b) If you intend to perform any of the actions specified in paragraph (a)(1) of this section, you must
meet the following additional requirements:
(1) Your APM (Form BSEE-0124) must contain a detailed statement of the proposed work that
would materially change from the approved APD. The submission of your APM must be accompanied by
payment of the service fee listed in §250.125;

(2) Your form BSEE-0124 must include the present status of the well, depth of all casing strings set
to date, well depth, present production zones and productive capability, and all other information
specified; and
(3) Within 30 days after completing this work, you must submit an End of Operations Report (EOR),
Form BSEE-0125, as required under §250.744.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26021, Apr. 29, 2016]

§§250.466--250.469 [Reserved]

ADDITIONAL ARCTIC OCS REQUIREMENTS
SOURCE: 81 FR 46561, July 15, 2016, unless otherwise noted.

§250.470 What additional information must I submit with my APD for Arctic OCS exploratory
drilling operations?
In addition to complying with all other applicable requirements included in this part, you must
provide with your APD all of the following information pertaining to your proposed Arctic OCS exploratory
drilling:
(a) A detailed description of:
(1) The environmental, meteorological, and oceanic conditions you expect to encounter at the well
site(s);
(2) How you will prepare your equipment, materials, and drilling unit for service in the conditions
identified in paragraph (a)(1) of this section, and how your drilling unit will be in compliance with the
requirements of §250.713.
(b) A detailed description of all operations necessary in Arctic OCS conditions to transition the rig
from being under way to conducting drilling operations and from ending drilling operations to being under
way, as well as any anticipated repair and maintenance plans for the drilling unit and equipment. You
should include, among other things, a description of how you plan to:
(1) Recover the subsea equipment, including the marine riser and the lower marine riser package;
(2) Recover the BOP;
(3) Recover the auxiliary sub-sea controls and template;
(4) Lay down the drill pipe and secure the drill pipe and marine riser;
(5) Secure the drilling equipment;
(6) Transfer the fluids for transport or disposal;
(7) Secure ancillary equipment like the draw works and lines;
(8) Refuel or transfer fuel;
(9) Offload waste;
(10) Recover the Remotely Operated Vehicles;

(11) Pick up the oil spill prevention booms and equipment; and
(12) Offload the drilling crew.
(c) A description of well-specific drilling objectives, timelines, and updated contingency plans for
temporary abandonment of the well, including but not limited to the following:
(1) When you will spud the particular well (i.e., begin drilling operations at the well site) identified in
the APD;
(2) How long you will take to drill the well;
(3) Anticipated depths and geologic targets, with timelines;
(4) When you expect to set and cement each string of casing;
(5) When and how you would log the well;
(6) Your plans to test the well;
(7) When and how you intend to abandon the well, including specifically addressing your plans for
how to move the rig off location and how you will meet the requirements of §250.720(c);
(8) A description of what equipment and vessels will be involved in the process of temporarily
abandoning the well due to ice; and
(9) An explanation of how you will integrate these elements into your overall program.
(d) A detailed description of your weather and ice forecasting capability for all phases of the drilling
operation, including:
(1) How you will ensure your continuous awareness of potential weather and ice hazards at, and
during transition between, wells;
(2) Your plans for managing ice hazards and responding to weather events; and
(3) Verification that you have the capabilities described in your BOEM-approved EP.
(e) A detailed description of how you will comply with the requirements of §250.472.
(f) A statement that you own, or have a contract with a provider for, source control and containment
equipment (SCCE), which is capable of controlling and/or containing a worst case discharge, as
described in your BOEM-approved EP, when proposing to use a MODU to conduct exploratory drilling
operations on the Arctic OCS. The following information must be included in your SCCE submittal:
(1) A detailed description of your or your contractor's SCCE capability to stop or contain flow from
an out-of-control well, including your operating assumptions and limitations; your access to and ability to
deploy, in accordance with §250.471, all necessary SCCE; and your ability to evaluate the performance
of the well design to determine how you can achieve a full shut-in without having reservoir fluids
discharged into the environment;
(2) An inventory of the local and regional SCCE, supplies, and services that you own or for which
you have a contract with a provider. You must identify each supplier of such equipment and services and
provide their locations and telephone numbers;
(3) Where applicable, proof of contracts or membership agreements with cooperatives, service

providers, or other contractors who will provide you with the necessary SCCE or related supplies and
services if you do not possess them. The contract or membership agreement must include provisions for
ensuring the availability of the personnel and/or equipment on a 24-hour per day basis while you are
drilling below or working below the surface casing;
(4) A detailed description of the procedures you plan to use to inspect, test, and maintain your
SCCE; and
(5) A detailed description of your plan to ensure that all members of your operating team, who are
responsible for operating the SCCE, have received the necessary training to deploy and operate such
equipment in Arctic OCS conditions and demonstrate ongoing proficiency in source control operations.
You must also identify and include the dates of prior and planned training.
(g) Where it does not conflict with other requirements of this subpart, and except as provided in
paragraphs (g)(1) through (11) of this section, you must comply with the requirements of API RP 2N,
Third Edition “Planning, Designing, and Constructing Structures and Pipelines for Arctic Conditions”
(incorporated by reference as specified in §250.198), and provide a detailed description of how you will
utilize the best practices included in API RP 2N during your exploratory drilling operations. You are not
required to incorporate the following sections of API RP 2N into your drilling operations:
(1) Sections 6.6.3 through 6.6.4;
(2) The foundation recommendations in Section 8.4;
(3) Section 9.6;
(4) The recommendations for permanently moored systems in Section 9.7;
(5) The recommendations for pile foundations in Section 9.10;
(6) Section 12;
(7) Section 13.2.1;
(8) Sections 13.8.1.1, 13.8.2.1, 13.8.2.2, 13.8.2.4 through 13.8.2.7;
(9) Sections 13.9.1, 13.9.2, 13.9.4 through 13.9.8;
(10) Sections 14 through 16; and
(11) Section 18.
§250.471 What are the requirements for Arctic OCS source control and containment?
You must meet the following requirements for all exploration wells drilled on the Arctic OCS:
(a) If you use a MODU when drilling below or working below the surface casing, you must have
access to the following SCCE capable of stopping or capturing the flow of an out-of-control well:
(1) A capping stack, positioned to ensure that it will arrive at the well location within 24 hours after a
loss of well control and can be deployed as directed by the Regional Supervisor pursuant to paragraph
(h) of this section;
(2) A cap and flow system, positioned to ensure that it will arrive at the well location within 7 days
after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to
paragraph (h) of this section. The cap and flow system must be designed to capture at least the amount

of hydrocarbons equivalent to the calculated worst case discharge rate referenced in your BOEMapproved EP; and
(3) A containment dome, positioned to ensure that it will arrive at the well location within 7 days
after a loss of well control and can be deployed as directed by the Regional Supervisor pursuant to
paragraph (h) of this section. The containment dome must have the capacity to pump fluids without
relying on buoyancy.
(b) You must conduct a monthly stump test of dry-stored capping stacks. If you use a pre-positioned
capping stack, you must conduct a stump test prior to each installation on each well.
(c) As required by §250.465(a), if you propose to change your well design, you must submit an
APM. For Arctic OCS operations, your APM must include a reevaluation of your SCCE capabilities for
any new Worst Case Discharge (WCD) rate, and a demonstration that your SCCE capabilities will meet
the criteria in §250.470(f) under the changed well design.
(d) You must conduct tests or exercises of your SCCE, including deployment of your SCCE, when
directed by the Regional Supervisor.
(e) You must maintain records pertaining to testing, inspection, and maintenance of your SCCE for
at least 10 years and make the records available to any authorized BSEE representative upon request.
(f) You must maintain records pertaining to the use of your SCCE during testing, training, and
deployment activities for at least 3 years and make the records available to any authorized BSEE
representative upon request.
(g) Upon a loss of well control, you must initiate transit of all SCCE identified in paragraph (a) of this
section to the well.
(h) You must deploy and use SCCE when directed by the Regional Supervisor.
(i) Operators may request approval of alternate procedures or equipment to the SCCE requirements
of subparagraph (a) of this section in accordance with §250.141. The operator must show and document
that the alternate procedures or equipment will provide a level of safety and environmental protection that
will meet or exceed the level of safety and environmental protection required by BSEE regulations,
including demonstrating that the alternate procedures or equipment will be capable of stopping or
capturing the flow of an out-of-control well.
§250.472 What are the relief rig requirements for the Arctic OCS?
(a) In the event of a loss of well control, the Regional Supervisor may direct you to drill a relief well
using the relief rig able to kill and permanently plug an out-of-control well as described in your APD. Your
relief rig must comply with all other requirements of this part pertaining to drill rig characteristics and
capabilities, and it must be able to drill a relief well under anticipated Arctic OCS conditions.
(b) When you are drilling below or working below the surface casing during Arctic OCS exploratory
drilling operations, you must have access to a relief rig, different from your primary drilling rig, staged in a
location such that it can arrive on site, drill a relief well, kill and abandon the original well, and abandon
the relief well prior to expected seasonal ice encroachment at the drill site, but no later than 45 days after
the loss of well control.
(c) Operators may request approval of alternative compliance measures to the relief rig requirement
in accordance with §250.141. The operator must show and document that the alternate compliance
measure will meet or exceed the level of safety and environmental protection required by BSEE
regulations, including demonstrating that the alternate compliance measure will be able to kill and
permanently plug an out-of-control well.

§250.473 What must I do to protect health, safety, property, and the environment while operating
on the Arctic OCS?
In addition to the requirements set forth in §250.107, when conducting exploratory drilling
operations on the Arctic OCS, you must protect health, safety, property, and the environment by using
the following:
(a) Equipment and materials that are rated or de-rated for service under conditions that can be
reasonably expected during your operations; and
(b) Measures to address human factors associated with weather conditions that can be reasonably
expected during your operations including, but not limited to, provision of proper attire and equipment,
construction of protected work spaces, and management of shifts.

HYDROGEN SULFIDE
§250.490 Hydrogen sulfide.
(a) What precautions must I take when operating in an H2S area? You must:
(1) Take all necessary and feasible precautions and measures to protect personnel from the toxic
effects of H2S and to mitigate damage to property and the environment caused by H2S. You must follow
the requirements of this section when conducting drilling, well-completion/well-workover, and production
operations in zones with H2S present and when conducting operations in zones where the presence of
H2S is unknown. You do not need to follow these requirements when operating in zones where the
absence of H2S has been confirmed; and
(2) Follow your approved contingency plan.
(b) Definitions. Terms used in this section have the following meanings:
Facility means a vessel, a structure, or an artificial island used for drilling, well-completion, wellworkover, and/or production operations.
H2S absent means:
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H2S in
concentrations that could potentially result in atmospheric concentrations of 20 ppm or more of H2S; or
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent
stratigraphic units have confirmed an absence of H2S throughout the area to be drilled.
H2S present means that drilling, logging, coring, testing, or producing operations have confirmed the
presence of H2S in concentrations and volumes that could potentially result in atmospheric
concentrations of 20 ppm or more of H2S.
H2S unknown means the designation of a zone or geologic formation where neither the presence
nor absence of H2S has been confirmed.
Well-control fluid means drilling mud and completion or workover fluid as appropriate to the
particular operation being conducted.
(c) Classifying an area for the presence of H2S. You must:
(1) Request and obtain an approved classification for the area from the Regional Supervisor before
you begin operations. Classifications are “H2S absent,” H2S present,” or “H2S unknown”;

(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as geologic and geophysical data and
correlations, well logs, formation tests, cores and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional data indicate a different
classification is needed.
(d) What do I do if conditions change? If you encounter H2S that could potentially result in
atmospheric concentrations of 20 ppm or more in areas not previously classified as having H2S present,
you must immediately notify BSEE and begin to follow requirements for areas with H2S present.
(e) What are the requirements for conducting simultaneous operations? When conducting any
combination of drilling, well-completion, well-workover, and production operations simultaneously, you
must follow the requirements in the section applicable to each individual operation.
(f) Requirements for submitting an H2S Contingency Plan. Before you begin operations, you must
submit an H2S Contingency Plan to the District Manager for approval. Do not begin operations before the
District Manager approves your plan. You must keep a copy of the approved plan in the field, and you
must follow the plan at all times. Your plan must include:
(1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the overall safety of personnel;
(4) Other key positions, how these positions fit into your organization, and what the functions,
duties, and responsibilities of those job positions are;
(5) Actions that you will take when the concentration of H2S in the atmosphere reaches 20 ppm,
who will be responsible for those actions, and a description of the audible and visual alarms to be
activated;
(6) Briefing areas where personnel will assemble during an H2S alert. You must have at least two
briefing areas on each facility and use the briefing area that is upwind of the H2S source at any given
time;
(7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely
evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H2S
alerts, describe the types of H2S emergencies during which you consider the risk of helicopter activity to
be acceptable and the precautions you will take during the flights;
(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you
will locate the vessels with respect to wind direction. Include the distance from the facility and what
procedures you will use to safely relocate the vessels in an emergency;
(9) How you will provide protective-breathing equipment for all personnel, including contractors and
visitors;
(10) The agencies and facilities you will notify in case of a release of H2S (that constitutes an
emergency), how you will notify them, and their telephone numbers. Include all facilities that might be
exposed to atmospheric concentrations of 20 ppm or more of H2S;
(11) The medical personnel and facilities you will use if needed, their addresses, and telephone
numbers;

(12) H2S detector locations in production facilities producing gas containing 20 ppm or more of H2S.
Include an “H2S Detector Location Drawing” showing:
(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H2S;
(ii) Approximate maximum concentration of H2S in the gas stream; and
(iii) Location of all H2S sensors included in your contingency plan;
(13) Operational conditions when you expect to flare gas containing H2S including the estimated
maximum gas flow rate, H2S concentration, and duration of flaring;
(14) Your assessment of the risks to personnel during flaring and what precautionary measures you
will take;
(15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and
monitoring the status of the flare (i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO2)-detection system(s) you will use to determine SO2
concentration and exposure hazard when H2S is burned;
(18) Increased monitoring and warning procedures you will take when the SO2 concentration in the
atmosphere reaches 2 ppm;
(19) Personnel protection measures or evacuation procedures you will initiate when the SO2
concentration in the atmosphere reaches 5 ppm;
(20) Engineering controls to protect personnel from SO2; and
(21) Any special equipment, procedures, or precautions you will use if you conduct any combination
of drilling, well-completion, well-workover, and production operations simultaneously.
(g) Training program: (1) When and how often do employees need to be trained? All operators and
contract personnel must complete an H2S training program to meet the requirements of this section:
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous class.
(2) What training documentation do I need? For each individual working on the platform, either:
(i) You must have documentation of this training at the facility where the individual is employed; or
(ii) The employee must carry a training completion card.
(3) What training do I need to give to visitors and employees previously trained on another facility?
(i) Trained employees or contractors transferred from another facility must attend a supplemental
briefing on your H2S equipment and procedures before beginning duty at your facility;
(ii) Visitors who will remain on your facility more than 24 hours must receive the training required for
employees by paragraph (g)(4) of this section; and
(iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training

required for employees, but they must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator; practice in donning and adjusting
the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H2S and
SO2; and
(B) Instructions on their responsibilities in the event of an H2S release.
(4) What training must I provide to all other employees? You must train all individuals on your
facility on the:
(i) Hazards of H2S and of SO2 and the provisions for personnel safety contained in the H2S
Contingency Plan;
(ii) Proper use of safety equipment which the employee may be required to use;
(iii) Location of protective breathing equipment, H2S detectors and alarms, ventilation equipment,
briefing areas, warning systems, evacuation procedures, and the direction of prevailing winds;
(iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in
conformance with ANSI Z88.2, American National Standard for Respiratory Protection (as specified in
§250.198);
(v) Basic first-aid procedures applicable to victims of H2S exposure. During all drills and training
sessions, you must address procedures for rescue and first aid for H2S victims;
(vi) Location of:
(A) The first-aid kit on the facility;
(B) Resuscitators; and
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5) Do I need to post safety information? You must prominently post safety information on the
facility and on vessels serving the facility (i.e., basic first-aid, escape routes, instructions for use of life
boats, etc.).
(h) Drills. (1) When and how often do I need to conduct drills on H2S safety discussions on the
facility? You must:
(i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day
period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H2S
considerations at the facility, and other updated H2S information at least monthly.
(2) What documentation do I need? You must keep records of attendance for:
(i) Drilling, well-completion, and well-workover operations at the facility until operations are
completed; and
(ii) Production operations at the facility or at the nearest field office for 1 year.

(i) Visual and audible warning systems: (1) How must I install wind direction equipment? You must
install wind-direction equipment in a location visible at all times to individuals on or in the immediate
vicinity of the facility.
(2) When do I need to display operational danger signs, display flags, or activate visual or audible
alarms?
(i) You must display warning signs at all times on facilities with wells capable of producing H2S and
on facilities that process gas containing H2S in concentrations of 20 ppm or more.
(ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing
red lights when atmospheric concentration of H2S reaches 20 ppm.
(3) What are the requirements for signs? Each sign must be a high-visibility yellow color with black
lettering as follows:
Letter height

Wording

12 inches

Danger.
Poisonous Gas.
Hydrogen Sulfide.

7 inches

Do not approach if red flag is flying.

(Use appropriate wording at right)

Do not approach if red lights are flashing.

(4) May I use existing signs? You may use existing signs containing the words “Danger-Hydrogen
Sulfide-H2S,” provided the words “Poisonous Gas. Do Not Approach if Red Flag is Flying” or “Red Lights
are Flashing” in lettering of a minimum of 7 inches in height are displayed on a sign immediately adjacent
to the existing sign.
(5) What are the requirements for flashing lights or flags? You must activate a sufficient number of
lights or hoist a sufficient number of flags to be visible to vessels and aircraft. Each light must be of
sufficient intensity to be seen by approaching vessels or aircraft any time it is activated (day or night).
Each flag must be red, rectangular, a minimum width of 3 feet, and a minimum height of 2 feet.
(6) What is an audible warning system? An audible warning system is a public address system or
siren, horn, or other similar warning device with a unique sound used only for H2S.
(7) Are there any other requirements for visual or audible warning devices? Yes, you must:
(i) Illuminate all signs and flags at night and under conditions of poor visibility; and
(ii) Use warning devices that are suitable for the electrical classification of the area.
(8) What actions must I take when the alarms are activated? When the warning devices are
activated, the designated responsible persons must inform personnel of the level of danger and issue
instructions on the initiation of appropriate protective measures.
(j) H2S-detection and H2S monitoring equipment: (1) What are the requirements for an H2S detection
system? An H2S detection system must:
(i) Be capable of sensing a minimum of 10 ppm of H2S in the atmosphere; and
(ii) Activate audible and visual alarms when the concentration of H2S in the atmosphere reaches 20
ppm.

(2) Where must I have sensors for drilling, well-completion, and well-workover operations? You
must locate sensors at the:
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H2S may accumulate.
(3) Do I need mud sensors? The District Manager may require mud sensors in the possum belly in
cases where the ambient air sensors in the mud-return system do not consistently detect the presence of
H2S.
(4) How often must I observe the sensors? During drilling, well-completion and well-workover
operations, you must continuously observe the H2S levels indicated by the monitors in the work areas
during the following operations:
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5) Where must I have sensors for production operations? On a platform where gas containing H2S
of 20 ppm or greater is produced, processed, or otherwise handled:
(i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise
covered by paragraph (j)(2) of this section, where atmospheric concentrations of H2S could reach 20 ppm
or more. You must have at least one sensor per 400 square feet of deck area or fractional part of 400
square feet;
(ii) You must have a sensor in buildings where personnel have their living quarters;
(iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or
pump, which could release enough H2S to result in atmospheric concentrations of 20 ppm at a distance of
10 feet from the component;
(iv) You may use one sensor to detect H2S around multiple pieces of equipment, provided the
sensor is located no more than 10 feet from each piece, except that you need to use at least two sensors
to monitor compressors exceeding 50 horsepower;
(v) You do not need to have sensors near wells that are shut in at the master valve and sealed

closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other devices subject to leaks to the
atmosphere; and
(B) Design factors, such as the type of decking and the location of fire walls; and
(vii) The District Manager may require additional sensors or other monitoring capabilities, if
warranted by site specific conditions.
(6) How must I functionally test the H2S Detectors? (i) Personnel trained to calibrate the particular
H2S detector equipment being used must test detectors by exposing them to a known concentration in
the range of 10 to 30 ppm of H2S.
(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of
the applied concentration, recalibrate the instrument.
(7) How often must I test my detectors? (i) When conducting drilling, drill stem testing, wellcompletion, or well-workover operations in areas classified as H2S present or H2S unknown, test all
detectors at least once every 24 hours. When drilling, begin functional testing before the bit is 1,500 feet
(vertically) above the potential H2S zone.
(ii) When conducting production operations, test all detectors at least every 14 days between tests.
(iii) If equipment requires calibration as a result of two consecutive functional tests, the District
Manager may require that H2S-detection and H2S-monitoring equipment be functionally tested and
calibrated more frequently.
(8) What documentation must I keep? (i) You must maintain records of testing and calibrations (in
the drilling or production operations report, as applicable) at the facility to show the present status and
history of each device, including dates and details concerning:
(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by BSEE personnel.
(9) What are the requirements for nearby vessels? If vessels are stationed overnight alongside
facilities in areas of H2S present or H2S unknown, you must equip vessels with an H2S-detection system
that activates audible and visual alarms when the concentration of H2S in the atmosphere reaches 20
ppm. This requirement does not apply to vessels positioned upwind and at a safe distance from the
facility in accordance with the positioning procedure described in the approved H2S Contingency Plan.
(10) What are the requirements for nearby facilities? The District Manager may require you to equip
nearby facilities with portable or fixed H2S detector(s) and to test and calibrate those detectors. To invoke

this requirement, the District Manager will consider dispersion modeling results from a possible release to
determine if 20 ppm H2S concentration levels could be exceeded at nearby facilities.
(11) What must I do to protect against SO2 if I burn gas containing H2S? You must:
(i) Monitor the SO2concentration in the air with portable or strategically placed fixed devices capable
of detecting a minimum of 2 ppm of SO2;
(ii) Take readings at least hourly and at any time personnel detect SO2 odor or nasal irritation;
(iii) Implement the personnel protective measures specified in the H2S Contingency Plan if the SO2
concentration in the work area reaches 2 ppm; and
(iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to
detect SO2.
(12) May I use alternative measures? You may follow alternative measures instead of those in
paragraph (j)(11) of this section if you propose and the Regional Supervisor approves the alternative
measures.
(13) What are the requirements for protective-breathing equipment? In an area classified as H2S
present or H2S unknown, you must:
(i) Provide all personnel, including contractors and visitors on a facility, with immediate access to
self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least
15 minutes.
(ii) Design, select, use, and maintain respirators in conformance with ANSI Z88.2 (as specified in
§250.198).
(iii) Make available at least two voice-transmission devices, which can be used while wearing a
respirator, for use by designated personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is quickly and easily accessible to all
personnel.
(vi) Label all breathing-air bottles as containing breathing-quality air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate protective-breathing equipment for
each crew member. The District Manager may require additional protective-breathing equipment on
certain vessels attendant to the facility.
(viii) During H2S alerts, limit helicopter flights to and from facilities to the conditions specified in the
H2S Contingency Plan. During authorized flights, the flight crew and passengers must use pressuredemand-type respirators. You must train all members of flight crews in the use of the particular type(s) of
respirator equipment made available.
(ix) As appropriate to the particular operation(s), (production, drilling, well-completion or wellworkover operations, or any combination of them), provide a system of breathing-air manifolds, hoses,
and masks at the facility and the briefing areas. You must provide a cascade air-bottle system for the
breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle
system may be recharged by a high-pressure compressor suitable for providing breathing-quality air,
provided the compressor suction is located in an uncontaminated atmosphere.
(k) Personnel safety equipment: (1) What additional personnel-safety equipment do I need? You

must ensure that your facility has:
(i) Portable H2S detectors capable of detecting a 10 ppm concentration of H2S in the air available for
use by all personnel;
(ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated
areas;
(iii) Chalkboards and/or note pads for communication purposes located on the rig floor, shaleshaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas
compressor area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number equal to the personnel on board,
not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and
spare oxygen bottles.
(2) What are the requirements for ventilation equipment? You must:
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H2S or SO2 may accumulate; and
(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be
multidirectional and capable of dispersing H2S or SO2 vapors away from working personnel.
(3) What other personnel safety equipment do I need? You must have the following equipment
readily available on each facility:
(i) A first-aid kit of appropriate size and content for the number of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l) Do I need to notify BSEE in the event of an H2S release? You must notify BSEE without delay in
the event of a gas release which results in a 15-minute time-weighted average atmospheric
concentration of H2S of 20 ppm or more anywhere on the OCS facility. You must report these gas
releases to the District Manager immediately by oral communication, with a written follow-up report within
15 days, pursuant to §§250.188 through 250.190.
(m) Do I need to use special drilling, completion and workover fluids or procedures? When working
in an area classified as H2S present or H2S unknown:
(1) You may use either water- or oil-base muds in accordance with §250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air sensors detect H2S, you must
immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm
the presence of H2S.
(3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must
don protective-breathing equipment conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of additives for the control of H2S, wellcontrol fluid pH, and corrosion equipment.
(i) Scavengers. You must have scavengers for control of H2S available on the facility. When H2S is

detected, you must add scavengers as needed. You must suspend drilling until the scavenger is
circulated throughout the system.
(ii) Control pH. You must add additives for the control of pH to water-base well-control fluids in
sufficient quantities to maintain pH of at least 10.0.
(iii) Corrosion inhibitors. You must add additives to the well-control fluid system as needed for the
control of corrosion.
(5) You must degas well-control fluids containing H2S at the optimum location for the particular
facility. You must collect the gases removed and burn them in a closed flare system conforming to
paragraph (q)(6) of this section.
(n) What must I do in the event of a kick? In the event of a kick, you must use one of the following
alternatives to dispose of the well-influx fluids giving consideration to personnel safety, possible
environmental damage, and possible facility well-equipment damage:
(1) Contain the well-fluid influx by shutting in the well and pumping the fluids back into the
formation.
(2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in
an open hole within the pressure limits of the well equipment (drill pipe, work string, casing, wellhead,
BOP system, and related equipment). The disposal of H2S and other gases must be through pressurized
or atmospheric mud-separator equipment depending on volume, pressure and concentration of H2S. The
equipment must be designed to recover well-control fluids and burn the gases separated from the wellcontrol fluid. The well-control fluid must be treated to neutralize H2S and restore and maintain the proper
quality.
(o) Well testing in a zone known to contain H2S. When testing a well in a zone with H2S present, you
must do all of the following:
(1) Before starting a well test, conduct safety meetings for all personnel who will be on the facility
during the test. At the meetings, emphasize the use of protective-breathing equipment, first-aid
procedures, and the Contingency Plan. Only competent personnel who are trained and are
knowledgeable of the hazardous effects of H2S must be engaged in these tests.
(2) Perform well testing with the minimum number of personnel in the immediate vicinity of the rig
floor and with the appropriate test equipment to safely and adequately perform the test. During the test,
you must continuously monitor H2S levels.
(3) Not burn produced gases except through a flare which meets the requirements of paragraph
(q)(6) of this section. Before flaring gas containing H2S, you must activate SO2 monitoring equipment in
accordance with paragraph (j)(11) of this section. If you detect SO2 in excess of 2 ppm, you must
implement the personnel protective measures in your H2S Contingency Plan, required by paragraph (f) of
this section. You must also follow the requirements of §250.1164. You must pipe gases from stored test
fluids into the flare outlet and burn them.
(4) Use downhole test tools and wellhead equipment suitable for H2S service.
(5) Use tubulars suitable for H2S service. You must not use drill pipe for well testing without the prior
approval of the District Manager. Water cushions must be thoroughly inhibited in order to prevent H2S
attack on metals. You must flush the test string fluid treated for this purpose after completion of the test.
(6) Use surface test units and related equipment that is designed for H2S service.
(p) Metallurgical properties of equipment. When operating in a zone with H2S present, you must use
equipment that is constructed of materials with metallurgical properties that resist or prevent sulfide

stress cracking (also known as hydrogen embrittlement, stress corrosion cracking, or H2S embrittlement),
chloride-stress cracking, hydrogen-induced cracking, and other failure modes. You must do all of the
following:
(1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related
equipment that is designed for H2S service.
(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment
exposed to H2S-bearing fluids in conformance with NACE Standard MR0175-03 (as specified in
§250.198).
(3) Use temporary downhole well-security devices such as retrievable packers and bridge plugs that
are designed for H2S service.
(4) When producing in zones bearing H2S, use equipment constructed of materials capable of
resisting or preventing sulfide stress cracking.
(5) Keep the use of welding to a minimum during the installation or modification of a production
facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking.
(q) General requirements when operating in an H2S zone: (1) Coring operations. When you conduct
coring operations in H2S-bearing zones, all personnel in the working area must wear protective-breathing
equipment at least 10 stands in advance of retrieving the core barrel. Cores to be transported must be
sealed and marked for the presence of H2S.
(2) Logging operations. You must treat and condition well-control fluid in use for logging operations
to minimize the effects of H2S on the logging equipment.
(3) Stripping operations. Personnel must monitor displaced well-control fluid returns and wear
protective-breathing equipment in the working area when the atmospheric concentration of H2S reaches
20 ppm or if the well is under pressure.
(4) Gas-cut well-control fluid or well kick from H2S-bearing zone. If you decide to circulate out a kick,
personnel in the working area during bottoms-up and extended-kill operations must wear protectivebreathing equipment.
(5) Drill- and workover-string design and precautions. Drill- and workover-strings must be designed
consistent with the anticipated depth, conditions of the hole, and reservoir environment to be
encountered. You must minimize exposure of the drill- or workover-string to high stresses as much as
practical and consistent with well conditions. Proper handling techniques must be taken to minimize
notching and stress concentrations. Precautions must be taken to minimize stresses caused by doglegs,
improper stiffness ratios, improper torque, whip, abrasive wear on tool joints, and joint imbalance.
(6) Flare system. The flare outlet must be of a diameter that allows easy nonrestricted flow of gas.
You must locate flare line outlets on the downside of the facility and as far from the facility as is feasible,
taking into account the prevailing wind directions, the wake effects caused by the facility and adjacent
structure(s), and the height of all such facilities and structures. You must equip the flare outlet with an
automatic ignition system including a pilot-light gas source or an equivalent system. You must have
alternate methods for igniting the flare. You must pipe to the flare system used for H2S all vents from
production process equipment, tanks, relief valves, burst plates, and similar devices.
(7) Corrosion mitigation. You must use effective means of monitoring and controlling corrosion
caused by acid gases (H2S and CO2) in both the downhole and surface portions of a production system.
You must take specific corrosion monitoring and mitigating measures in areas of unusually severe
corrosion where accumulation of water and/or higher concentration of H2S exists.
(8) Wireline lubricators. Lubricators which may be exposed to fluids containing H2S must be of H2Sresistant materials.

(9) Fuel and/or instrument gas. You must not use gas containing H2S for instrument gas. You must
not use gas containing H2S for fuel gas without the prior approval of the District Manager.
(10) Sensing lines and devices. Metals used for sensing line and safety-control devices which are
necessarily exposed to H2S-bearing fluids must be constructed of H2S-corrosion resistant materials or
coated so as to resist H2S corrosion.
(11) Elastomer seals. You must use H2S-resistant materials for all seals which may be exposed to
fluids containing H2S.
(12) Water disposal. If you dispose of produced water by means other than subsurface injection,
you must submit to the District Manager an analysis of the anticipated H2S content of the water at the
final treatment vessel and at the discharge point. The District Manager may require that the water be
treated for removal of H2S. The District Manager may require the submittal of an updated analysis if the
water disposal rate or the potential H2S content increases.
(13) Deck drains. You must equip open deck drains with traps or similar devices to prevent the
escape of H2S gas into the atmosphere.
(14) Sealed voids. You must take precautions to eliminate sealed spaces in piping designs (e.g.,
slip-on flanges, reinforcing pads) which can be invaded by atomic hydrogen when H2S is present.