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(1) You move a drilling rig or related equipment on and off a platform. This includes rigging up and rigging down activities within 500 feet of the affected platform;
(2) You move or skid a drilling unit between wells on a platform;
(3) A mobile offshore drilling unit (MODU) moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin drilling operations.
[68 FR 8423, Feb. 20, 2003]
§ 250.407 What tests must I conduct to determine reservoir characteristics?
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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.
[68 FR 8423, Feb. 20, 2003]
§ 250.408 May I use alternative procedures or equipment during drilling operations?
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You may use alternative procedures or equipment during drilling operations after receiving approval from the District Supervisor. You must identify and discuss your proposed alternative procedures or equipment in your Application for Permit to Drill (APD) (see §250.414(h)). Procedures for obtaining approval are described in section 250.141 of this part.
[68 FR 8423, Feb. 20, 2003]
§ 250.409 May I obtain departures from these drilling requirements?
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The District Supervisor 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 Supervisor. You should identify and discuss the departure you are requesting in your APD (see §250.414(h)).
[68 FR 8423, Feb. 20, 2003]
Applying for a Permit To Drill
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§ 250.410 How do I obtain approval to drill a well?
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You must obtain written approval from the District Supervisor 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 253; and
(d) Submit the following forms to the District Supervisor:
(1) An original and two complete copies of form MMS–123, Application for a Permit to Drill (APD), and form MMS–123S, Supplemental APD Information Sheet; and
(2) A separate public information copy of forms MMS–123 and MMS–123S that meets the requirements of §250.127.
[68 FR 8423, Feb. 20, 2003]
§ 250.411 What information must I submit with my application?
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In addition to forms MMS–123 and MMS–123S, you must include the information described in the following table.
------------------------------------------------------------------------
Information that you must include with an Where to find a
APD description
------------------------------------------------------------------------
(a) Plat that shows locations of the § 250.412
proposed well.
(b) Design criteria used for the proposed § 250.413
well.
(c) Drilling prognosis..................... § 250.414
(d) Casing and cementing programs.......... § 250.415
(e) Diverter and BOP systems descriptions.. § 250.416
(f) Requirements for using an MODU......... § 250.417
(g) Additional information................. § 250.418
------------------------------------------------------------------------
[68 FR 8423, Feb. 20, 2003]
§ 250.412 What requirements must the location plat meet?
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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.
[68 FR 8423, Feb. 20, 2003]
§ 250.413 What must my description of well drilling design criteria address?
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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 estimated pore pressures, formation fracture gradients, proposed drilling fluid weights, 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.
[68 FR 8423, Feb. 20, 2003]
§ 250.414 What must my drilling prognosis include?
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Your drilling prognosis must include a brief description of the procedures you will follow in drilling the well. This prognosis includes but is not limited to the following:
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin between proposed drilling fluid weights and estimated pore pressures. This safe drilling margin may be shown on the plot required by §250.413(g);
(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 alternative procedures or departures from the requirements of this subpart in one place in the APD. You must explain how the alternative procedures afford an equal or greater degree of protection, safety, or performance, or why you need the departures; and
(i) Projected plans for well testing (refer to §250.460 for safety requirements).
[68 FR 8423, Feb. 20, 2003]
§ 250.415 What must my casing and cementing programs include?
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Your casing and cementing programs must include:
(a) Hole sizes and casing sizes, including: weights; grades; collapse, and burst values; types of connection; and setting depths (measured and true vertical depth (TVD));
(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; and
(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.
[68 FR 8423, Feb. 20, 2003]
§ 250.416 What must I include in the diverter and BOP descriptions?
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You must include in the diverter and BOP descriptions:
(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 annular BOP 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;
(c) A description of the BOP system and system components, including pressure ratings of BOP equipment and proposed BOP test pressures;
(d) A schematic drawing of the BOP system that shows the inside diameter of the BOP stack, number and type of preventers, location of choke and kill lines, and associated valves; and
(e) Information that shows the blind-shear rams installed in the BOP stack (both surface and subsea stacks) are capable of shearing the drill pipe in the hole under maximum anticipated surface pressures.
[68 FR 8423, Feb. 20, 2003]
§ 250.417 What must I provide if I plan to use a mobile offshore drilling unit (MODU)?
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If you plan to use a MODU, you must provide:
(a) Fitness requirements. You must provide information and data to demonstrate the drilling unit's capability to perform at the proposed drilling location. This information must include the maximum environmental and operational conditions that the unit is designed to withstand, including the minimum air gap necessary for both hurricane and non-hurricane seasons. If sufficient environmental information and data are not available at the time you submit your APD, the District Supervisor may approve your APD but require you to collect and report this information during operations. Under this circumstance, the District Supervisor has the right to revoke the approval of the APD if information collected during operations show that the drilling unit is not capable of performing at the proposed location.
(b) Foundation requirements. You must provide information to show that site-specific soil and oceanographic conditions are capable of supporting the proposed drilling unit. If you provided sufficient site-specific information in your EP, DPP, or DOCD, you may reference that information. The District Supervisor may require you to conduct additional surveys and soil borings before approving the APD if additional information is needed to make a determination that the conditions are capable of supporting the drilling unit.
(c) Frontier areas. (1) If the design of the drilling unit you plan to use in a frontier area is unique or has not been proven for use in the proposed environment, the District Supervisor may require you to submit a third-party review of the unit's design. If required, you must obtain the third-party review according to §250.903. You may submit this information before submitting an APD.
(2) If you plan to drill in a frontier area, you must have a contingency plan that addresses design and operating limitations of the drilling unit. Your plan must identify the actions necessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of drilling or rig operations to remedy various operational or environmental situations (e.g. vessel motion, riser offset, anchor tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt or lateral movement, resupply capability).
(d) U.S. Coast Guard (USCG) documentation. You must provide the current Certificate of Inspection or Letter of Compliance from the USCG. You must also provide current documentation of any operational limitations imposed by an appropriate classification society.
(e) Floating drilling unit. If you use a floating drilling unit, you must indicate that you have a contingency plan for moving off location in an emergency situation.
(f) Inspection of unit. The drilling unit must be available for inspection by the District Supervisor before commencing operations.
(g) Once the District Supervisor has approved a MODU for use, you do not need to re-submit the information required by this section for another APD to use the same MODU unless changes in equipment affect its rated capacity to operate in the District.
[68 FR 8423, Feb. 20, 2003]
§ 250.418 What additional information must I submit with my APD?
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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 some cement to facilitate casing removal upon well abandonment; and
(h) Such other information as the District Supervisor may require.
[68 FR 8423, Feb. 20, 2003]
Casing and Cementing Requirements
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§ 250.420 What well casing and cementing requirements must I meet?
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You must case and cement all wells. Your casing and cementing programs must meet the requirements of this section and of §§250.421 through 250.428.
(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; and
(5) Support unconsolidated sediments.
(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.
(c) Cementing requirements. 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 of the casing or before commencing completion operations.
[68 FR 8423, Feb. 20, 2003]
§ 250.421 What are the casing and cementing requirements by type of casing string?
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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 Supervisor may approve or prescribe other casing and cementing requirements where appropriate.
------------------------------------------------------------------------
Casing Cementing
Casing type requirements requirements
------------------------------------------------------------------------
(a) Drive or Structural......... Set by driving, If you drilled a
jetting, or portion of this
drilling to the hole, you must
minimum depth as use enough cement
approved or to fill the
prescribed by the annular space
District back to the
Supervisor. mudline.
(b) Conductor................... Design casing and Use enough cement
select setting to fill the
depths based on calculated
relevant annular space
engineering and back to the
geologic factors. mudline.
These factors Verify annular
include the fill by observing
presence or cement returns.
absence of If you cannot
hydrocarbons, observe cement
potential returns, use
hazards, and additional cement
water depths. to ensure fill-
Set casing back to the
immediately mudline.
before drilling For drilling on an
into formations artificial island
known to contain or when using a
oil or gas. If glory hole, you
you encounter oil must discuss the
or gas or cement fill level
unexpected with the District
formation Supervisor.
pressure before
the planned
casing point, you
must set casing
immediately.
(c) Surface..................... Design casing and Use enough cement
select setting to fill the
depths based on calculated
relevant annular space to
engineering and at least 200 feet
geologic factors. inside the
These factors conductor casing.
include the When geologic
presence or conditions such
absence of as near-surface
hydrocarbons, fractures and
potential faulting exist,
hazards, and you must use
water depths. enough cement to
fill the
calculated
annular space to
the mudline.
(d) Intermediate................ Design casing and Use enough cement
select setting to cover and
depth based on isolate all
anticipated or hydrocarbon-
encountered bearing zones and
geologic isolate abnormal
characteristics pressure
or wellbore intervals from
conditions. normal pressure
intervals in the
well.
As a minimum, you
must cement the
annular space 500
feet above the
casing shoe and
500 feet above
each zone to be
isolated.
(e) Production.................. Design casing and Use enough cement
select setting to cover or
depth based on isolate all
anticipated or hydrocarbon-
encountered bearing zones
geologic above the shoe.
characteristics As a minimum, you
or wellbore must cement the
conditions. annular space at
least 500 feet
above the casing
shoe and 500 feet
above the
uppermost
hydrocarbon-
bearing zone.
(f) Liners...................... If you use a liner Same as cementing
as conductor or requirements for
surface casing, specific casing
you must set the types. For
top of the liner example, a liner
at least 200 feet used as
above the intermediate
previous casing/ casing must be
liner shoe. cemented
If you use a liner according to the
as an cementing
intermediate requirements for
string below a intermediate
surface string or casing.
production casing
below an
intermediate
string, you must
set the top of
the liner at
least 100 feet
above the
previous casing
shoe..
------------------------------------------------------------------------
[68 FR 8423, Feb. 20, 2003]
§ 250.422 When may I resume drilling after cementing?
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(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.
[68 FR 8423, Feb. 20, 2003]
§ 250.423 What are the requirements for pressure testing casing?
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The table in this section describes the minimum test pressures for each string of casing. You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you must re-cement, repair the casing, or run additional casing to provide a proper seal. The District Supervisor may approve or require other casing test pressures.
------------------------------------------------------------------------
Casing type Minimum test pressure
------------------------------------------------------------------------
(a) Drive or Structural................... Not required
(b) Conductor............................. 200 psi
(c) Surface, Intermediate, and Production. 70 percent of its minimum
internal yield
------------------------------------------------------------------------
[68 FR 8423, Feb. 20, 2003]
§ 250.424 What are the requirements for prolonged drilling operations?
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If wellbore operations continue for more than 30 days within a casing string run to the surface:
(a) You must stop drilling operations as soon as practicable, and evaluate the effects of the prolonged operations on continued drilling operations and the life of the well. At a minimum, you must:
(1) Caliper or pressure test the casing; and
(2) Report the results of your evaluation to the District Supervisor and obtain approval of those results before resuming operations.
(b) If casing integrity has deteriorated to a level below minimum safety factors, you must:
(1) Repair the casing or run another casing string; and
(2) Obtain approval from the District Supervisor before you begin repairs.
[68 FR 8423, Feb. 20, 2003]
§ 250.425 What are the requirements for pressure testing liners?
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(a) You must test each drilling liner (and liner-lap) to a pressure at least equal to the anticipated pressure to which the liner will be subjected during the formation pressure-integrity test below that liner shoe, or subsequent liner shoes if set. The District Supervisor may approve or require other liner test pressures.
(b) You must test each production liner (and liner-lap) to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped.
(c) You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you must re-cement, repair the liner, or run additional casing/liner to provide a proper seal.
[68 FR 8423, Feb. 20, 2003]
§ 250.426 What are the recordkeeping requirements for casing and liner pressure tests?
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You must record the time, date, and results of each pressure test in the driller's report maintained under standard industry practice. In addition, you must record each test on a pressure chart and have your onsite representative sign and date the test as being correct.
[68 FR 8423, Feb. 20, 2003]
§ 250.427 What are the requirements for pressure integrity tests?
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You must conduct a pressure integrity test below the surface casing or liner and all intermediate casings or liners. The District Supervisor 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 the approved APD. When you cannot maintain this safe margin, you must suspend drilling operations and remedy the situation.
[68 FR 8423, Feb. 20, 2003]
§ 250.428 What must I do in certain cementing and casing situations?
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The table in this section describes actions that lessees must take when certain situations occur during casing and cementing activities.
------------------------------------------------------------------------
If you encounter the following
situation: Then you must . . .
------------------------------------------------------------------------
(a) Have unexpected formation Submit a revised casing program to the
pressures or conditions that District Supervisor for approval.
warrant revising your casing
design.
(b) Need to increase casing Submit those changes to the District
setting depths more than 100 Supervisor for approval.
feet true vertical depth (TVD)
from the approved APD due to
conditions encountered during
drilling operations.
(c) Have indication of (1) Pressure test the casing shoe; (2)
inadequate cement job (such as Run a temperature survey; (3) Run a
lost returns, cement cement bond log; or (4) Use a
channeling, or failure of combination of these techniques.
equipment).
(d) Inadequate cement job....... Re-cement or take other remedial
actions as approved by the District
Supervisor.
(e) Primary cement job that did Isolate those intervals from normal
not isolate abnormal pressure pressures by squeeze cementing before
intervals. you complete; suspend operations; or
abandon the well, whichever occurs
first.
(f) Decide to produce a well Have at least two cemented casing
that was not originally strings (does not include liners) in
contemplated for production. the well. Note: All producing wells
must have at least two cemented
casing strings.
(g) Want to drill a well without Submit geologic data and information
setting conductor casing. to the District Supervisor 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
required cement for the surface Supervisor that demonstrates the use
casing during floating drilling of less cement is necessary.
operations to provide
protection from burst and
collapse pressures.
(i) Cement across a permafrost Use cement that sets before it freezes
zone. and has a low heat of hydration.
(j) Leave the annulus opposite a Fill the annulus with a liquid that
permafrost zone uncemented. has a freezing point below the
minimum permafrost temperature and
minimizes opposite a corrosion.
------------------------------------------------------------------------
[68 FR 8423, Feb. 20, 2003]
Diverter System Requirements
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§ 250.430 When must I install a diverter system?
top
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.
[68 FR 8423, Feb. 20, 2003]
§ 250.431 What are the diverter design and installation requirements?
top
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches for surface wellhead configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind diversion capability;
(c) Use at least two diverter control stations. One station must be on the drilling floor. The other station must be in a readily accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All valves in the diverter system must be full-opening. You may not install manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed for each line for bottom-founded drilling units) in the diverter lines, maximize the radius of curvature of turns, and target all right angles and sharp turns;
(f) Anchor and support the entire diverter system to prevent whipping and vibration; and
(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects.
[68 FR 8423, Feb. 20, 2003]
§ 250.432 How do I obtain a departure to diverter design and installation requirements?
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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 Supervisor.
------------------------------------------------------------------------
If you want a departure to: Then you must...
------------------------------------------------------------------------
(a) Use flexible hose for Use flexible hose that has integral
diverter lines instead of rigid end couplings.
pipe.
(b) Use only one spool outlet (1) Have branch lines that meet the
for your diverter system. minimum internal diameter
requirements; and (2) Provide
downwind diversion capability.
(c) Use a spool with an outlet Use a spool that has dual outlets with
with an internal diameter of an internal diameter of at least 8
less than 10 inches on a inches.
surface wellhead.
(d) Use a single diverter line Maintain an appropriate vessel heading
for floating drilling to provide for downwind diversion.
operations on a dynamically
positioned drillship.
------------------------------------------------------------------------
[68 FR 8423, Feb. 20, 2003]
§ 250.433 What are the diverter actuation and testing requirements?
top
When you install the diverter system, you must actuate the diverter sealing element, diverter valves, and diverter-control systems and control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration, you must actuate the diverter system at least once every 24-hour period after the initial test. After you have nippled up on conductor casing, you must pressure-test the diverter-sealing element and diverter valves to a minimum of 200 psi. While the diverter is installed, you must conduct subsequent pressure tests within 7 days after the previous test.
(b) For floating drilling operations with a subsea BOP stack, you must actuate the diverter system within 7 days after the previous actuation.
(c) You must alternate actuations and tests between control stations.
[68 FR 8423, Feb. 20, 2003]
§ 250.434 What are the recordkeeping requirements for diverter actuations and tests?
top
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.
[68 FR 8423, Feb. 20, 2003]
Blowout Preventer (BOP) System Requirements
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§ 250.440 What are the general requirements for BOP systems and system components?
top
You must design, install, maintain, test, and use the BOP system and system components to ensure well control. The working-pressure rating of each BOP component must exceed maximum anticipated surface pressures. The BOP system includes the BOP stack and associated BOP systems and equipment.
[68 FR 8423, Feb. 20, 2003]
§ 250.441 What are the requirements for a surface BOP stack?
top
(a) When you drill with a surface BOP stack, you must install the BOP system before drilling below surface casing. The surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind or blind-shear rams.
(b) No later than February 21, 2006, your surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind-shear rams. The blind-shear rams must be capable of shearing the drill pipe that is in the hole.
(c) You must install an accumulator system that provides 1.5 times the volume of fluid capacity necessary to close and hold closed all BOP components. The system must perform with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. If you supply the accumulator regulators by rig air and do not have a secondary source of pneumatic supply, you must equip the regulators with manual overrides or other devices to ensure capability of hydraulic operations if rig air is lost.
(d) In addition to the stack and accumulator system, you must install the associated BOP systems and equipment required by the regulations in this subpart.
[68 FR 8423, Feb. 20, 2003]
§ 250.442 What are the requirements for a subsea BOP stack?
top
(a) When you drill with a subsea BOP stack, you must install the BOP system before drilling below surface casing. The District Supervisor may require you to install a subsea BOP system before drilling below the conductor casing if proposed casing setting depths or local geology indicate the need.
(b) Your subsea BOP stack must include at least four remote-controlled, hydraulically operated BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind-shear rams.
(c) You must install an accumulator closing system to provide fast closure of the BOP components and to operate all critical functions in case of a loss of the power fluid connection to the surface. The accumulator system must meet or exceed the provisions of Section 13.3, Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in §250.198). The District Supervisor may approve a suitable alternative method.
(d) The BOP system must include an operable dual-pod control system to ensure proper and independent operation of the BOP system.
(e) Before removing the marine riser, you must displace the riser with seawater. You must maintain sufficient hydrostatic pressure or take other suitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition.
[68 FR 8423, Feb. 20, 2003]
§ 250.443 What associated systems and related equipment must all BOP systems include?
top
All BOP systems must include the following associated systems and related equipment:
(a) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components.
(b) At least two BOP control stations. One station must be on the drilling floor. You must locate the other station in a readily accessible location away from the drilling floor.
(c) Side outlets on the BOP stack for separate kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side outlets.
(d) A choke and a kill line on the BOP stack. You must equip each line with two full-opening valves, one of which must be remote-controlled. For a subsea BOP system, both valves in each line must be remote-controlled. In addition:
(1) You must install the choke line above the bottom ram;
(2) You may install the kill line below the bottom ram; and
(3) For a surface BOP system, on the kill line you may install a check valve and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be readily accessible and you must install the check valve between the manual valves and the pump.
(e) A fill-up line above the uppermost BOP.
(f) Locking devices installed on the ram-type BOPs.
(g) A wellhead assembly with a rated working pressure that exceeds the maximum anticipated surface pressure.
[68 FR 8423, Feb. 20, 2003]
§ 250.444 What are the choke manifold requirements?
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(a) Your BOP system must include a choke manifold that is suitable for the anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of drilling fluids and well fluids that you may encounter.
(b) Choke manifold components must have a rated working pressure at least as great as the rated working pressure of the ram BOPs. If your choke manifold has buffer tanks downstream of choke assemblies, you must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings upstream of the choke manifold must have a rated working pressure at least as great as the rated working pressure of the ram BOPs.
[68 FR 8423, Feb. 20, 2003]
§ 250.445 What are the requirements for kelly valves, inside BOPs, and drill-string safety valves?
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You must use or provide the following BOP equipment during drilling operations:
(a) A kelly valve installed below the swivel (upper kelly valve);
(b) A kelly valve installed at the bottom of the kelly (lower kelly valve). You must be able to strip the lower kelly valve through the BOP stack;
(c) If you drill with a mud motor and use drill pipe instead of a kelly, you must install one kelly valve above, and one strippable kelly valve below, the joint of drill pipe used in place of a kelly;
(d) On a top-drive system equipped with a remote-controlled valve, you must install a strippable kelly-type valve below the remote-controlled valve;
(e) An inside BOP in the open position located on the rig floor. You must be able to install an inside BOP for each size connection in the drill string;
(f) A drill-string safety valve in the open position located on the rig floor. You must have a drill-string safety valve available for each size connection in the drill string;
(g) When running casing, you must have a safety valve in the open position available on the rig floor to fit the casing string being run in the hole;
(h) All required manual and remote-controlled kelly valves, drill-string safety valves, and comparable-type valves (i.e. kelly-type valve in a top-drive system) must be essentially full-opening; and
(i) The drilling crew must have ready access to a wrench to fit each manual valve.
[68 FR 8423, Feb. 20, 2003]
§ 250.446 What are the BOP maintenance and inspection requirements?
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(a) You must maintain your BOP system to ensure that the equipment functions properly. BOP maintenance must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in §250.198).
(b) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP system and marine riser at least once every 3 days if weather and sea conditions permit. You may use television cameras to inspect subsea equipment.
[68 FR 8423, Feb. 20, 2003]
§ 250.447 When must I pressure test the BOP system?
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You must pressure test your BOP system (this includes the choke manifold, kelly valves, inside BOP, and drill-string safety valve):
(a) When installed;
(b) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before midnight on the 14th day following the conclusion of the previous test. However, the District Supervisor may require more frequent testing if conditions or BOP performance warrant; and
(c) Before drilling out each string of casing or a liner. The District Supervisor may allow you to omit this test if you didn't remove the BOP stack to run the casing string or liner and the required BOP test pressures for the next section of the hole are not greater than the test pressures for the previous BOP test. You must indicate in your APD which casing strings and liners meet these criteria.
[68 FR 8423, Feb. 20, 2003]
§ 250.448 What are the BOP pressure tests requirements?
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When you pressure test the BOP system, you must conduct a low-pressure and a high-pressure test for each BOP component. You must conduct the low-pressure test before the high-pressure test. Each individual pressure test must hold pressure long enough to demonstrate that the tested component(s) holds the required pressure. Required test pressures are as follows:
(a) Low-pressure test. All low-pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test.
(b) High-pressure test for ram-type BOPs, the choke manifold, and other BOP components. The high-pressure test must equal the rated working pressure of the equipment or be 500 psi greater than your calculated maximum anticipated surface pressure (MASP) for the applicable section of hole. Before you may test BOP equipment to the MASP plus 500 psi, the District Supervisor must have approved those test pressures in your APD.
(c) High pressure test for annular-type BOPs. The high pressure test must equal 70 percent of the rated working pressure of the equipment or to a pressure approved in your APD.
(d) Duration of pressure test. Each test must hold the required pressure for 5 minutes. However, for surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder. If the equipment does not hold the required pressure during a test, you must correct the problem and retest the affected component(s).
[68 FR 8423, Feb. 20, 2003]
§ 250.449 What additional BOP testing requirements must I meet?
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You must meet the following additional BOP testing requirements:
(a) Use water to test a surface BOP system;
(b) Stump test a subsea BOP system before installation. You must use water to conduct this test. You may use drilling fluids to conduct subsequent tests of a subsea BOP system;
(c) Alternate tests between control stations and pods;
(d) Pressure test the blind or blind-shear ram BOP during stump tests and at all casing points;
(e) The interval between any blind or blind-shear ram BOP pressure tests may not exceed 30 days;
(f) Pressure test variable bore-pipe ram BOPs against the largest and smallest sizes of pipe in use, excluding drill collars and bottom-hole tools;
(g) Pressure test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(h) Function test annular and ram BOPs every 7 days between pressure tests; and
(i) Actuate safety valves assembled with proper casing connections before running casing.
[68 FR 8423, Feb. 20, 2003]
§ 250.450 What are the recordkeeping requirements for BOP tests?
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You must record the time, date, and results of all pressure tests, actuations, and inspections of the BOP system, system components, and marine riser in the driller's report. In addition, you must:
(a) Record BOP test pressures on pressure charts;
(b) Require your onsite representative to sign and date BOP test charts and reports as correct; (continued)