eCFR for 30 CFR 250, Subpart D

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[A1]

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

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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   How do I obtain approval to drill a well?
§250.411   What information must I submit with my application?
§250.412   What requirements must the location plat meet?
§250.413   What must my description of well drilling design criteria address?
§250.414   What must my drilling prognosis include?
§250.415   What must my casing and cementing programs include?
§250.416   What must I include in the diverter description?
§250.417   [Reserved]
§250.418   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   When must I install a diverter system?
§250.431   What are the diverter design and installation requirements?
§250.432   How do I obtain a departure to diverter design and installation requirements?
§250.433   What are the diverter actuation and testing requirements?
§250.434   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

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§250.455   What are the general requirements for a drilling fluid program?
§250.456   What safe practices must the drilling fluid program follow?
§250.457   What equipment is required to monitor drilling fluids?
§250.458   What quantities of drilling fluids are required?
§250.459   What are the safety requirements for drilling fluid-handling areas?
OthEr DrillinG REquirEmEnts
§250.460   What are the requirements for conducting a well test?
§250.461   What are the requirements for directional and inclination surveys?
§250.462   What are the source control, containment, and collocated equipment requirements?
§250.463   Who establishes 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?
§§250.466-250.469   [Reserved]
ADDitional Arctic OCS REquirEmEnts
§250.470   What additional information must I submit with my APD for Arctic OCS exploratory drilling operations?
§250.471   What are the requirements for Arctic OCS source control and containment?
§250.472   What are the relief rig requirements for the Arctic OCS?
§250.473   What must I do to protect health, safety, property, and theenvironment while operating on the Arctic OCS?
HYDroGEn SulfiDE
§250.490   Hydrogen sulfide.
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GENEraL REQUIrEmENTs
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§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]

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§§250.401-250.403   [Reserved]
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§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.
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§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;

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(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]

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§250.406   [Reserved]
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§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.
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§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.
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§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)).
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APPLYINg for a PErmIT To DrILL
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§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.
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§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:

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Information that you must include with an APD
(a) Plat that shows locations of the proposed well,
(b) Design criteria used for the proposed well,
(c) Drilling prognosis,
(d) Casing and cementing programs,
(e) Diverter systems descriptions,
(f) BOP system descriptions,
(g) Requirements for using a MODU, and
(h) Additional information.

Where to find a description
§250.412.
§250.413.
§250.414.
§250.415.
§250.416.
§250.731.
§250.713.
§250.418.

[81 FR 26017, Apr. 29, 2016]

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§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 grid-system
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.
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§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 (surface and downhole), 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; 84 FR 21973, May 15, 2019]

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§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:

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(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, offset well data, analog data, seismic data) to justify the alternative equivalent downhole mud weight. You may submit
such justification in advance of your full APD, and BSEE may consider such justification for approval when submitted.
Any such approval will be contingent upon your confirmation in the APD that your plans and the information underlying
your approved justification have not changed.
(3) When determining the pore pressure and lowest estimated fracture gradient for a specific interval, you must
consider related off-set and analogous well behavior observations, if available.
(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; 84 FR 21973, May 15, 2019]

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§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

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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]

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§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]

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§250.417   [Reserved]
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§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]

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CasINg aNd CEmENTINg REQUIrEmENTs
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§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 consistent with the guidelines of API Standard 65—Part 2 (as incorporated by
reference in §250.198); 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; 84 FR 21973, May 15, 2019]

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§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 Set by driving, jetting, or drilling to the minimum depth as If you drilled a portion of this hole, you must
Structural
approved or prescribed by the District Manager
use enough cement to fill the annular space
back to the mudline.
(b)
Design casing and select setting depths based on relevant Use enough cement to fill the calculated
annular space back to the mudline.
Conductor engineering and geologic factors. These factors include
Verify annular fill by observing cement
the presence or absence of hydrocarbons, potential

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hazards, and water depths
returns. If you cannot observe cement
Set casing immediately before drilling into formations
returns, use additional cement to ensure fillknown to contain oil or gas. If you encounter oil or gas or back to the mudline.
unexpected formation pressure before the planned casing For drilling on an artificial island or when
point, you must set casing immediately and set it above
using a well cellar, you must discuss the
the encountered zone
cement fill level with the District Manager.
(c) Surface Design casing and select setting depths based on relevant Use enough cement to fill the calculated
annular space to at least 200 feet measured
engineering and geologic factors. These factors include
depth (MD) inside the conductor casing.
the presence or absence of hydrocarbons, potential
When geologic conditions such as nearhazards, and water depths
surface fractures and faulting exist, you must
use enough cement to fill the calculated
annular space to the mudline.
Use enough cement to cover and isolate all
(d)
Design casing and select setting depth based on
hydrocarbon-bearing zones and isolate
Intermediate anticipated or encountered geologic characteristics or
abnormal pressure intervals from normal
wellbore conditions
pressure intervals in the well.
As a minimum, you must cement the annular
space 500 feet MD above the casing shoe
and 500 feet MD above each zone to be
isolated.
Use enough cement to cover or isolate all
(e)
Design casing and select setting depth based on
hydrocarbon-bearing zones above the shoe.
Production anticipated or encountered geologic characteristics or
As a minimum, you must cement the annular
wellbore conditions
space at least 500 feet MD above the casing
shoe and 500 feet MD above the uppermost
hydrocarbon-bearing zone.
(f) Liners
If you use a liner as surface casing, you must set the top Same as cementing requirements for specific
casing types. For example, a liner used as
of the liner at least 200 feet MD above the previous
intermediate casing must be cemented
casing/liner shoe.
If you use a liner as an intermediate string below a surface according to the cementing requirements for
string or production casing below an intermediate string, intermediate casing.
you must set the top of the liner at least 100 feet MD
above 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; 84 FR 21974, May 15, 2019]

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§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.
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§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 the casing string.
(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 the liner.
(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.

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[81 FR 26019, Apr. 29, 2016, as amended at 84 FR 21974, May 15, 2019]

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§§250.424-250.426   [Reserved]
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§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 pore-pressure 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 margin identified in §250.414. When you cannot maintain the
safe drilling margin, you must:
(1) Suspend drilling operations and submit proposed remedial actions to the District Manager. The District
Manager must review and approve your proposed remedial actions, which may include limited drilling through a lost
circulation zone; or
(2) Notify the District Manager and take further action in accordance with API Bulletin 92L (as incorporated by
reference in §250.198), if appropriate. You must submit a revised permit documenting any responsive actions taken.
[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26019, Apr. 29, 2016; 84 FR 21974, May 15, 2019]

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§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:
(a) Have unexpected
formation pressures or
conditions that warrant
revising your casing
design,
(b) Need to change
casing setting depths or
hole interval drilling depth
(for a BHA with an underreamer, this means bit
depth) more than 100
feet true vertical depth
(TVD) from the approved
APD due to conditions
encountered during
drilling operations,
(c) Have indication of
inadequate cement job
(such as unplanned lost
returns, no cement
returns to mudline or
expected height, cement
channeling, or failure of
equipment),
(d) Inadequate cement
job,

Then you must .  .  .
Submit a revised casing program to the District Manager for approval.

Submit those changes to the District Manager for approval and include a certification by a
professional engineer (PE) that he or she reviewed and approved the proposed changes.

(1) Locate the top of cement by:
(i) Running a temperature survey;
(ii) Running a cement evaluation log;
(iii) Using tracers in the cement and logging them prior to drill out; or
(iv) 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.
Comply with §250.428(c)(1) and take remedial actions. The District Manager must review
and approve all remedial actions either through a previously approved contingency plan
within the permit or remedial actions included in a revised permit 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

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(e) Primary cement job
that did not isolate
abnormal pressure
intervals,
(f) Decide to produce a
well that was not
originally contemplated
for production,
(g) Want to drill a well
without setting conductor
casing,

Manager when that action is complete. Any changes to the well program, that are not
included in the approved permit, will require submittal of a certification by a professional
engineer (PE) certifying that they have reviewed and approved the proposed changes. You
must also meet any other requirements of the District Manager for remedial actions.
Isolate those intervals from normal pressures by squeeze cementing before you complete;
suspend operations; or abandon the well, whichever occurs first.

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.

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 Submit information to the District Manager that demonstrates the use of less cement is
required cement for the necessary.
surface casing during
floating drilling operations
to provide protection from
burst and collapse
pressures,
(i) Cement across a
Use cement that sets before it freezes and has a low heat of hydration.
permafrost zone,
Fill the annulus with a liquid that has a freezing point below the minimum permafrost
(j) Leave the annulus
temperature and minimizes opposite a corrosion.
opposite a permafrost
zone uncemented,
(k) Plan to use a valve(s) Include a description of the plan in your APD. Your description must include a schematic of
on the drive pipe during the valve and height above the water line. The valve must be remotely operated and full
cementing operations for 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
the conductor casing,
surface casing, or liner, 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; 84 FR 21974, May 15, 2019]

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DIVErTEr SYsTEm REQUIrEmENTs
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§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.
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§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

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(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects.
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§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:
(a) Use flexible hose for diverter lines instead of
rigid pipe,
(b) Use only one spool outlet for your diverter
system,
(c) Use a spool with an outlet with an internal
diameter of less than 10 inches on a surface
wellhead,
(d) Use a single diverter line for floating drilling
operations on a dynamically positioned drillship,

Then you must .  .  .
Use flexible hose that has integral end couplings.
(1) Have branch lines that meet the minimum internal diameter
requirements; and (2) Provide downwind diversion capability.
Use a spool that has dual outlets with an internal diameter of at
least 8 inches.
Maintain an appropriate vessel heading to provide for downwind
diversion.

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§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 divertercontrol 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. For subsequent testing, you may partially actuate the diverter element and a flow test is
not required.
(c) You must alternate actuations and tests between control stations.
[76 FR 64462, Oct. 18, 2011, as amended at 84 FR 21975, May 15, 2019]

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§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.
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§§250.440-250.451   [Reserved]
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§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;

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(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 real-time 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]

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DrILLINg FLUId REQUIrEmENTs
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§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.
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§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 drill-stem test string and tools
with an appropriate kill weight fluid;

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(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]

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§250.457   What equipment is required to monitor drilling fluids?
Once you establish drilling fluid returns, you must install and maintain the following drilling fluid-system 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 fluidlogging 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.
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§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.
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§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 air-volume 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

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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.
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OThEr DrILLINg REQUIrEmENTs
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§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.
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§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 a 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 180 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.
[76 FR 64462, Oct. 18, 2011, as amended at 84 FR 21975, May 15, 2019]

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§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 based on the determinations outlined in paragraph (a) of this section. This SCCE,
supporting equipment, and collocated equipment may 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
(1) Capping stacks,

Requirements, you must:
(i) Function test all pressure containing
critical components on a quarterly frequency
(not to exceed 104 days between tests),

Additional information
Pressure containing critical components are
those components that will experience
wellbore pressure during a shut-in after
being functioned.

(ii) Pressure test pressure containing critical Pressure containing critical components are
those components that will experience
components on a bi-annual basis, but not
wellbore pressure during a shut-in. These
later than 210 days from the last pressure
test. All pressure testing must be witnessed components include, but are not limited to:
by BSEE (if available) and an independent All blind rams, wellhead connectors, and
outlet valves.
third party.

(iii) Notify BSEE at least 21 days prior to
commencing any pressure testing
(i) Meet or exceed the requirements set forth
(2) Production safety
systems used for flow and in Subpart H, excluding required equipment
that would be installed below the wellhead or
capture operations,
that is not applicable to the cap and flow

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system.
(ii) Have all equipment unique to
containment operations available for
inspection at all times
(3) Subsea utility
Have all equipment utilized solely for
equipment,
containment operations available for
inspection at all times
(4) Collocated equipment Have equipment available for inspection at
designated by the operator all times
in the Regional
Containment
Demonstration (RCD) or
Well Containment Plan
(WCP),

Subsea utility equipment includes, but is not
limited to: Hydraulic power sources, debris
removal, and hydrate control equipment.
Collocated equipment includes, but is not
limited to, dispersant injection equipment
and other subsea control equipment.

[81 FR 26020, Apr. 29, 2016, as amended at 84 FR 21975, May 15, 2019]

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§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.
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APPLYINg for a PErmIT To ModIfY aNd WELL REcords
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§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 .  .  .
(1) Intend to revise
your drilling plan,
change major drilling
equipment, or
plugback,
(2) Determine a
well's final surface
location, water
depth, and the rotary
kelly bushing
elevation,
(3) Move a drilling
unit from a wellbore
before completing a
well,

Then you must .  .  .
Submit form BSEE0124 or request oral
approval,

And .  .  .
Receive written or oral approval from the District 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.
Immediately Submit a Submit a plat certified by a registered land surveyor that meets the
form BSEE-0124,
requirements of §250.412.

Submit forms BSEE- Submit appropriate copies of the well records.
0124 and BSEE-0125
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 BSEE0125, as required under §250.744.

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[76 FR 64462, Oct. 18, 2011, as amended at 81 FR 26021, Apr. 29, 2016]

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§§250.466-250.469   [Reserved]
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AddITIoNaL ArcTIc OCS REQUIrEmENTs
SourcE: 81 FR 46561, July 15, 2016, unless otherwise noted.

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§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

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(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 BOEMapproved 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-ofcontrol 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.
Back to Top
§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

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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 BOEM-approved 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.
Back to Top
§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.
Back to Top
§250.473   What must I do to protect health, safety, property, and theenvironment 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.

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Back to Top

HYdrogEN SULfIdE
Back to Top
§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, well-workover, 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

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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

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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 winddirection 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
12 inches

7 inches

Wording
Danger.
Poisonous Gas.
Hydrogen Sulfide.
Do not approach if red flag is flying.

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(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

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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, well-completion, or wellworkover 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.

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(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 pressure-demand-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 well-workover 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, shale-shaker 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

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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, well-control 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 well-control 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, hydrogeninduced 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-

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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 protective-breathing 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 H2S-resistant
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.
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