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(continued)

(c) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. For subsea BOP systems, you must also record the closing times for annular and ram BOPs. You may reference a BOP test plan if it is available at the facility;

(d) Identify the control station and pod used during the test;

(e) Identify any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities; and

(f) Retain all records, including pressure charts, driller's report, and referenced documents pertaining to BOP tests, actuations, and inspections at the facility for the duration of drilling.

[68 FR 8423, Feb. 20, 2003]

§ 250.451 What must I do in certain situations involving BOP equipment or systems?
top
The table in this section describes actions that lessees must take when certain situations occur with BOP systems during drilling activities.



------------------------------------------------------------------------
If you encounter the following situation: Then you must . . .
------------------------------------------------------------------------
(a) BOP equipment does not hold the Correct the problem and
required pressure during a test. retest the affected
equipment.
(b) Need to repair or replace a surface or First place the well in a
subsea BOP system. safe, controlled condition
(e.g., before drilling out
a casing shoe or after
setting a cement plug,
bridge plug, or a packer).
(c) Need to postpone a BOP test due to Record the reason for
well-control problems such as lost postponing the test in the
circulation, formation fluid influx, or driller's report and
stuck drill pipe. conduct the required BOP
test on the first trip out
of the hole.
(d) BOP control station or pod that does Suspend further drilling
not function properly. operations until that
station or pod is operable.
(e) Want to drill with a tapered drill- Install two or more sets of
string. conventional or variable-
bore pipe rams in the BOP
stack to provide for the
following: two sets of rams
must be capable of sealing
around the larger-size
drill string and one set of
pipe rams must be capable
of sealing around the
smaller-size drill string.
(f) Install casing rams in a BOP stack.... Test the ram bonnets before
running casing.
(g) Want to use an annular BOP with a Demonstrate that your well
rated working pressure less than the control procedures or the
anticipated surface pressure. anticipated well conditions
will not place demands
above its rated working
pressure and obtain
approval from the District
Supervisor.
(h) Use a subsea BOP system in an ice- Install the BOP stack in a
scour area. glory hole. The glory hole
must be deep enough to
ensure that the top of the
stack is below the deepest
probable ice-scour depth.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

Drilling Fluid Requirements
top
§ 250.455 What are the general requirements for a drilling fluid program?
top
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.

[68 FR 8423, Feb. 20, 2003]

§ 250.456 What safe practices must the drilling fluid program follow?
top
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 Supervisor). 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 Supervisor);

(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;

(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 Supervisor 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.

[68 FR 8423, Feb. 20, 2003; 68 FR 14274, Mar. 24, 2003]

§ 250.457 What equipment is required to monitor drilling fluids?
top
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 fluid-logging compartment or on the rig floor. If the indicators are only in the logging compartment, you must continually man the equipment and have a means of immediate communication with the rig floor. If the indicators are on the rig floor only, you must install an audible alarm.

[68 FR 8423, Feb. 20, 2003]

§ 250.458 What quantities of drilling fluids are required?
top
(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.

[68 FR 8423, Feb. 20, 2003]

§ 250.459 What are the safety requirements for drilling fluid-handling areas?
top
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 (incorporated by reference as specified 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 (incorporated by reference as specified 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 Supervisor;

(b) Gas detectors and alarms except in open areas where adequate ventilation is provided by natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse between tests;

(c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you must locate the air intake outside of and as far as practicable from hazardous areas; and

(d) Alarms that activate when the mechanical ventilation system fails.

[68 FR 8423, Feb. 20, 2003]

Other Drilling Requirements
top
§ 250.460 What are the requirements for conducting a well test?
top
(a) If you intend to conduct a well test, you must include your projected plans for the test with your APD (form MMS–123) or in an Application for Permit to Modify (APM) (form MMS–124). 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 Supervisor at least 24-hours notice before starting a well test.

[68 FR 8423, Feb. 20, 2003]

§ 250.461 What are the requirements for directional and inclination surveys?
top
For this subpart, MMS classifies a well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical.

(a) Survey requirements for a vertical well. (1) You must conduct inclination surveys on each vertical well and record the results. Survey intervals may not exceed 1,000 feet during the normal course of drilling;

(2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally record the results in electronic format:

(i) Within 500 feet of setting surface or intermediate casing;

(ii) Within 500 feet of setting any liner; and

(iii) When you reach total depth.

(b) Survey requirements for directional well. You must conduct directional surveys on each directional well and digitally record the results. Surveys must give both inclination and azimuth at intervals not to exceed 500 feet during the normal course of drilling. Intervals during angle-changing portions of the hole may not exceed 100 feet.

(c) Measurement while drilling. You may use measurement-while-drilling technology if it meets the requirements of this section.

(d) Composite survey requirements. (1) Your composite directional survey must show the interval from the bottom of the conductor casing to total depth. In the absence of conductor casing, the survey must show the interval from the bottom of the drive or structural casing to total depth; and

(2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections used and include a listing of the directionally computed inclinations and azimuths.

(e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights.

[68 FR 8423, Feb. 20, 2003]

§ 250.462 What are the requirements for well-control drills?
top
You must conduct a weekly well-control drill with each drilling crew. Your drill must familiarize the crew with its roles and functions so that all crew members can perform their duties promptly and efficiently.

(a) Well-control drill plan. You must prepare a well control drill plan for each well. Your plan must outline the assignments for each crew member and establish times to complete each portion of the drill. You must post a copy of the well control drill plan on the rig floor or bulletin board.

(b) Timing of drills. You must conduct each drill during a period of activity that minimizes the risk to drilling operations. The timing of your drills must cover a range of different operations, including drilling with a diverter, on-bottom drilling, and tripping.

(c) Recordkeeping requirements. For each drill, you must record the following in the driller's report:

(1) The time to be ready to close the diverter or BOP system; and

(2) The total time to complete the entire drill.

(d) MMS ordered drill. An MMS authorized representative may require you to conduct a well control drill during an MMS inspection. The MMS representative will consult with your onsite representative before requiring the drill.

[68 FR 8423, Feb. 20, 2003]

§ 250.463 Who establishes field drilling rules?
top
(a) The District Supervisor 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 Supervisor may amend or cancel field drilling rules at any time.

(b) You may request the District Supervisor to establish, amend, or cancel field drilling rules.

[68 FR 8423, Feb. 20, 2003]

Applying for a Permit To Modify and Well Records
top
§ 250.465 When must I submit an Application for Permit to Modify (APM) or an End of Operations Report to MMS?
top
(a) You must submit an APM (form MMS–124) or an End of Operations Report (form MMS–125) and other materials to the Regional Supervisor as shown in the following table. You must also submit a public information copy of each form.



------------------------------------------------------------------------
When you Then you must And
------------------------------------------------------------------------
(1) Intend to revise your Submit form MMS- Receive written or
drilling plan, change major 124 or request oral approval from
drilling equipment, or oral approval. the District
plugback. Supervisor before
you begin the
intended operation.
If you get an
approval, you must
submit form MMS-124
no later than the
end of the 3rd
business day
following the oral
approval. In all
cases, or you must
meet the additional
requirements in
paragraph (b) of
this section.
(2) Determine a well's final Immediately Submit a plat
surface location, water Submit a form certified by a
depth, and the rotary kelly MMS-124. registered land
bushing elevation. surveyor that meets
the requirements of
§ 250.412.
(3) Move a drilling unit from Submit forms MMS- Submit appropriate
a wellbore before completing 124 and MMS-125 copies of the well
a well. within 30 days records.
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 form MMS–124 must contain a detailed statement of the proposed work that will materially change from the approved APD;

(2) Your form MMS–124 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 form MMS–124 with detailed information about the work to the District Supervisor, unless you have already provided sufficient information in a Well Activity Report, form MMS–133 (§250.468(b)).

[68 FR 8423, Feb. 20, 2003]

§ 250.466 What records must I keep?
top
You must keep complete, legible, and accurate records for each well. You must keep drilling records onsite while drilling activities continue. After completion of drilling activities, you must keep all drilling and other well records for the time periods shown in §250.469. You may keep these records at a location of your choice. The records must contain complete information on all of the following:

(a) Well operations;

(b) Descriptions of formations penetrated;

(c) Content and character of oil, gas, water, and other mineral deposits in each formation;

(d) Kind, weight, size, grade, and setting depth of casing;

(e) All well logs and surveys run in the wellbore;

(f) Any significant malfunction or problem; and

(g) All other information required by the District Supervisor in the interests of resource evaluation, waste prevention, conservation of natural resources, and the protection of correlative rights, safety, and environment.

[68 FR 8423, Feb. 20, 2003]

§ 250.467 How long must I keep records?
top
You must keep records for the time periods shown in the following table.



------------------------------------------------------------------------
You must keep records relating to Until
------------------------------------------------------------------------
(a) Drilling........................... Ninety days after you complete
drilling operations.
(b) Casing and liner pressure tests, Two years after the completion
diverter tests, and BOP tests. of drilling operations.
(c) Completion of a well or of any You permanently plug and
workover activity that materially abandon the well or until you
alters the completion configuration or forward the records with a
affects a hydrocarbon-bearing zone. lease assignment.
------------------------------------------------------------------------


[68 FR 8423, Feb. 20, 2003]

§ 250.468 What well records am I required to submit?
top
(a) You must submit copies of logs or charts of electrical, radioactive, sonic, and other well-logging operations; directional and vertical-well surveys; velocity profiles and surveys; and analysis of cores to MMS. Each Region will provide specific instructions for submitting well logs and surveys.

(b) For drilling operations in the GOM OCS Region, you must submit form MMS–133, Well Activity Report, to the District Supervisor on a weekly basis.

(c) For drilling operations in the Pacific or Alaska OCS Regions, you must submit form MMS–133, Well Activity Report, to the District Supervisor on a daily basis.

[68 FR 8423, Feb. 20, 2003]

§ 250.469 What other well records could I be required to submit?
top
The Regional or District Supervisor may require you to submit copies of any or all of the following well records.

(a) Well records as specified in §250.466;

(b) Paleontological interpretations or reports identifying microscopic fossils by depth and/or washed samples of drill cuttings that you normally maintain for paleontological determinations. The Regional Supervisor may issue a Notice to Lessees that prescribes the manner, timeframe, and format for submitting this information;

(c) Service company reports on cementing, perforating, acidizing, testing, or other similar services; or

(d) Other reports and records of operations.

[68 FR 8423, Feb. 20, 2003]

Hydrogen Sulfide
top
§ 250.490 Hydrogen sulfide.
top
Link to an amendment published at 71 FR 19645, April 17, 2006.

(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 MMS 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 Supervisor for approval. Do not begin operations before the District Supervisor approves your plan. You must keep a copy of the approved plan in the field, and you must follow the plan at all times. Your plan must include:

(1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking;

(2) Training you provide for employees, contractors, and visitors;

(3) Job position and title of the person responsible for the overall safety of personnel;

(4) Other key positions, how these positions fit into your organization, and what the functions, duties, and responsibilities of those job positions are;

(5) Actions that you will take when the concentration of H2S in the atmosphere reaches 20 ppm, who will be responsible for those actions, and a description of the audible and visual alarms to be activated;

(6) Briefing areas where personnel will assemble during an H2S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H2S source at any given time;

(7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H2S alerts, describe the types of H2S emergencies during which you consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights;

(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an emergency;

(9) How you will provide protective-breathing equipment for all personnel, including contractors and visitors;

(10) The agencies and facilities you will notify in case of a release of H2S (that constitutes an emergency), how you will notify them, and their telephone numbers. Include all facilities that might be exposed to atmospheric concentrations of 20 ppm or more of H2S;

(11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers;

(12) H2S detector locations in production facilities producing gas containing 20 ppm or more of H2S. Include an “H2S Detector Location Drawing” showing:

(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H2S;

(ii) Approximate maximum concentration of H2S in the gas stream; and

(iii) Location of all H2S sensors included in your contingency plan;

(13) Operational conditions when you expect to flare gas containing H2S including the estimated maximum gas flow rate, H2S concentration, and duration of flaring;

(14) Your assessment of the risks to personnel during flaring and what precautionary measures you will take;

(15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and monitoring the status of the flare (i.e., ignited or extinguished);

(16) Procedures to shut off the gas to the flare in the event the flare is extinguished;

(17) Portable or fixed sulphur dioxide (SO2)-detection system(s) you will use to determine SO2 concentration and exposure hazard when H2S is burned;

(18) Increased monitoring and warning procedures you will take when the SO2 concentration in the atmosphere reaches 2 ppm;

(19) Personnel protection measures or evacuation procedures you will initiate when the SO2 concentration in the atmosphere reaches 5 ppm;

(20) Engineering controls to protect personnel from SO2; and

(21) Any special equipment, procedures, or precautions you will use if you conduct any combination of drilling, well-completion, well-workover, and production operations simultaneously.

(g) Training program—(1) When and how often do employees need to be trained? All operators and contract personnel must complete an H2S training program to meet the requirements of this section:

(i) Before beginning work at the facility; and

(ii) Each year, within 1 year after completion of the previous class.

(2) What training documentation do I need? For each individual working on the platform, either:

(i) You must have documentation of this training at the facility where the individual is employed; or

(ii) The employee must carry a training completion card.

(3) What training do I need to give to visitors and employees previously trained on another facility?—(i) Trained employees or contractors transferred from another facility must attend a supplemental briefing on your H2S equipment and procedures before beginning duty at your facility;

(ii) Visitors who will remain on your facility more than 24 hours must receive the training required for employees by paragraph (g)(4) of this section; and

(iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training required for employees, but they must, upon arrival, complete a briefing that includes:

(A) Information on the location and use of an assigned respirator; practice in donning and adjusting the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H2S and SO2; and

(B) Instructions on their responsibilities in the event of an H2S release.

(4) What training must I provide to all other employees? You must train all individuals on your facility on the:

(i) Hazards of H2S and of SO2 and the provisions for personnel safety contained in the H2S Contingency Plan;

(ii) Proper use of safety equipment which the employee may be required to use;

(iii) Location of protective breathing equipment, H2S detectors and alarms, ventilation equipment, briefing areas, warning systems, evacuation procedures, and the direction of prevailing winds;

(iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in conformance with ANSI Z88.2, American National Standard for Respiratory Protection (incorporated by reference as specified in §250.198);

(v) Basic first-aid procedures applicable to victims of H2S exposure. During all drills and training sessions, you must address procedures for rescue and first aid for H2S victims;

(vi) Location of:

(A) The first-aid kit on the facility;

(B) Resuscitators; and

(C) Litter or other device on the facility.

(vii) Meaning of all warning signals.

(5) Do I need to post safety information? You must prominently post safety information on the facility and on vessels serving the facility (i.e., basic first-aid, escape routes, instructions for use of life boats, etc.).

(h) Drills. (1) When and how often do I need to conduct drills on H2S safety discussions on the facility? You must:

(i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs.

(ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H2S considerations at the facility, and other updated H2S information at least monthly.

(2) What documentation do I need? You must keep records of attendance for:

(i) Drilling, well-completion, and well-workover operations at the facility until operations are completed; and

(ii) Production operations at the facility or at the nearest field office for 1 year.

(i) Visual and audible warning systems—(1) How must I install wind direction equipment? You must install wind-direction equipment in a location visible at all times to individuals on or in the immediate vicinity of the facility.

(2) When do I need to display operational danger signs, display flags, or activate visual or audible alarms?—(i) You must display warning signs at all times on facilities with wells capable of producing H2S and on facilities that process gas containing H2S in concentrations of 20 ppm or more.

(ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing red lights when atmospheric concentration of H2S reaches 20 ppm.

(3) What are the requirements for signs? Each sign must be a high-visibility yellow color with black lettering as follows:



------------------------------------------------------------------------
Letter height Wording
------------------------------------------------------------------------
12 inches................................. Danger.
Poisonous Gas.
Hydrogen Sulfide.
7 inches.................................. Do not approach if red flag
is flying.
(Use appropriate wording at right)........ Do not approach if red
lights are flashing.
------------------------------------------------------------------------


(4) May I use existing signs? You may use existing signs containing the words “Danger-Hydrogen Sulfide-H2S,” provided the words “Poisonous Gas. Do Not Approach if Red Flag is Flying” or “Red Lights are Flashing” in lettering of a minimum of 7 inches in height are displayed on a sign immediately adjacent to the existing sign.

(5) What are the requirements for flashing lights or flags? You must activate a sufficient number of lights or hoist a sufficient number of flags to be visible to vessels and aircraft. Each light must be of sufficient intensity to be seen by approaching vessels or aircraft any time it is activated (day or night). Each flag must be red, rectangular, a minimum width of 3 feet, and a minimum height of 2 feet.

(6) What is an audible warning system? An audible warning system is a public address system or siren, horn, or other similar warning device with a unique sound used only for H2S.

(7) Are there any other requirements for visual or audible warning devices? Yes, you must:

(i) Illuminate all signs and flags at night and under conditions of poor visibility; and

(ii) Use warning devices that are suitable for the electrical classification of the area.

(8) What actions must I take when the alarms are activated? When the warning devices are activated, the designated responsible persons must inform personnel of the level of danger and issue instructions on the initiation of appropriate protective measures.

(j) H2S-detection and H2S monitoring equipment—(1) What are the requirements for an H2S detection system? An H2S detection system must:

(i) Be capable of sensing a minimum of 10 ppm of H2S in the atmosphere; and

(ii) Activate audible and visual alarms when the concentration of H2S in the atmosphere reaches 20 ppm.

(2) Where must I have sensors for drilling, well-completion, and well-workover operations? You must locate sensors at the:

(i) Bell nipple;

(ii) Mud-return line receiver tank (possum belly);

(iii) Pipe-trip tank;

(iv) Shale shaker;

(v) Well-control fluid pit area;

(vi) Driller's station;

(vii) Living quarters; and

(viii) All other areas where H2S may accumulate.

(3) Do I need mud sensors? The District Supervisor may require mud sensors in the possum belly in cases where the ambient air sensors in the mud-return system do not consistently detect the presence of H2S.

(4) How often must I observe the sensors? During drilling, well-completion and well-workover operations, you must continuously observe the H2S levels indicated by the monitors in the work areas during the following operations:

(i) When you pull a wet string of drill pipe or workover string;

(ii) When circulating bottoms-up after a drilling break;

(iii) During cementing operations;

(iv) During logging operations; and

(v) When circulating to condition mud or other well-control fluid.

(5) Where must I have sensors for production operations? On a platform where gas containing H2S of 20 ppm or greater is produced, processed, or otherwise handled:

(i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise covered by paragraph (j)(2) of this section, where atmospheric concentrations of H2S could reach 20 ppm or more. You must have at least one sensor per 400 square feet of deck area or fractional part of 400 square feet;

(ii) You must have a sensor in buildings where personnel have their living quarters;

(iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H2S to result in atmospheric concentrations of 20 ppm at a distance of 10 feet from the component;

(iv) You may use one sensor to detect H2S around multiple pieces of equipment, provided the sensor is located no more than 10 feet from each piece, except that you need to use at least two sensors to monitor compressors exceeding 50 horsepower;

(v) You do not need to have sensors near wells that are shut in at the master valve and sealed closed;

(vi) When you determine where to place sensors, you must consider:

(A) The location of system fittings, flanges, valves, and other devices subject to leaks to the atmosphere; and

(B) Design factors, such as the type of decking and the location of fire walls; and

(vii) The District Supervisor 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 well-workover operations in areas classified as H2S present or H2S unknown, test all detectors at least once every 24 hours. When drilling, begin functional testing before the bit is 1,500 feet (vertically) above the potential H2S zone.

(ii) When conducting production operations, test all detectors at least every 14 days between tests.

(iii) If equipment requires calibration as a result of two consecutive functional tests, the District Supervisor 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 MMS 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 Supervisor 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 Supervisor 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 SO2 concentration in the air with portable or strategically placed fixed devices capable of detecting a minimum of 2 ppm of SO2;

(ii) Take readings at least hourly and at any time personnel detect SO2 odor or nasal irritation;

(iii) Implement the personnel protective measures specified in the H2S Contingency Plan if the SO2 concentration in the work area reaches 2 ppm; and

(iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to detect SO2.

(12) May I use alternative measures? You may follow alternative measures instead of those in paragraph (j)(11) of this section if you propose and the Regional Supervisor approves the alternative measures.

(13) What are the requirements for protective-breathing equipment? In an area classified as H2S present or H2S unknown, you must:

(i) Provide all personnel, including contractors and visitors on a facility, with immediate access to self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least 15 minutes.

(ii) Design, select, use, and maintain respirators in conformance with ANSI Z88.2 (incorporated by reference 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 Supervisor 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 MMS in the event of an H2S release? You must notify MMS 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 facility.

(m) Do I need to use special drilling, completion and workover fluids or procedures? When working in an area classified as H2S present or H2S unknown:

(1) You may use either water- or oil-base muds in accordance with §250.300(b)(1).

(2) If you use water-base well-control fluids, and if ambient air sensors detect H2S, you must immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H2S.

(3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must don protective-breathing equipment conforming to paragraph (j)(13) of this section.

(4) You must maintain on the facility sufficient quantities of additives for the control of H2S, 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. (continued)