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(continued)
(1) You may be subject to MMS enforcement action, including civil penalties; and
(2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will not be entitled to compensation under §250.185(b) and 30 CFR 256.77.
(b) Emergencies. Nothing in this subpart or in your approved EP, DPP, or DOCD relieves you of, or limits your responsibility to take appropriate measures to meet emergency situations. In an emergency situation, the Regional Supervisor may approve or require departures from your approved EP, DPP, or DOCD.
§ 250.281 What must I do to conduct activities under the approved EP, DPP, or DOCD?
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(a) Approvals and permits. Before you conduct activities under your approved EP, DPP, or DOCD you must obtain the following approvals and or permits, as applicable, from the District Manager or Regional Supervisor:
(1) Approval of applications for permits to drill (APDs) (see §250.410);
(2) Approval of production safety systems (see §250.800);
(3) Approval of new platforms and other structures (or major modifications to platforms and other structures) (see §250.901);
(4) Approval of applications to install lease term pipelines (see §250.1007); and
(5) Other permits, as required by applicable law.
(b) Conformance. The activities proposed in these applications and permits must conform to the activities described in detail in your approved EP, DPP, or DOCD.
(c) Separate State CZMA consistency review. APDs, and other applications for licenses, approvals, or permits to conduct activities under your approved EP, DPP, or DOCD including those identified in paragraph (a) of this section, are not subject to separate State CZMA consistency review.
(d) Approval restrictions for permits for activities conducted under EPs. The District Manager or Regional Supervisor will not approve any APDs or other applications for licenses, approvals, or permits under your approved EP until either:
(1) All affected States with approved coastal zone management programs concur, or are conclusively presumed to concur, with the coastal zone consistency certification accompanying your EP under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by the EP is consistent with the objectives of the CZMA or is otherwise necessary in the interest of national security;
(3) If an affected State objects to the coastal zone consistency certification accompanying your approved EP after MMS has approved your EP, you may either:
(i) Revise your EP to accommodate the State's objection and submit the revision to the Regional Supervisor for approval; or
(ii) Appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930 subpart H. The Secretary of Commerce will either:
(A) Grant your appeal by making the finding described in paragraph (d)(2) of this section; or
(B) Deny your appeal, in which case you may revise your EP as described in paragraph (d)(3)(i) of this section.
§ 250.282 Do I have to conduct post-approval monitoring?
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After approving your EP, DPP, or DOCD the Regional Supervisor may direct you to conduct monitoring programs. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to MMS upon request. The timeframe for retention of all monitoring data will be stipulated in the approval letter. The Regional Supervisor may require you to:
(a) Monitoring plans. Submit monitoring plans for approval before you begin the work; and
(b) Monitoring reports. Prepare and submit reports that summarize and analyze data and information obtained or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.
§ 250.283 When must I revise or supplement the approved EP, DPP, or DOCD?
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(a) Revised OCS plans. You must revise your approved EP, DPP, or DOCD when you propose to:
(1) Change the type of drilling rig (e.g., jack-up, platform rig, barge, submersible, semisubmersible, or drillship), production facility (e.g., caisson, fixed platform with piles, tension leg platform), or transportation mode (e.g., pipeline, barge);
(2) Change the surface location of a well or production platform by a distance more than that specified by the Regional Supervisor;
(3) Change the type of production or significantly increase the volume of production or storage capacity;
(4) Increase the emissions of an air pollutant to an amount that exceeds the amount specified in your approved EP, DPP, or DOCD;
(5) Significantly increase the amount of solid or liquid wastes to be handled or discharged;
(6) Request a new H2S area classification, or increase the concentration of H2S to a concentration greater than that specified by the Regional Supervisor;
(7) Change the location of your onshore support base either from one State to another or to a new base or a base requiring expansion; or
(8) Change any other activity specified by the Regional Supervisor.
(b) Supplemental OCS plans. You must supplement your approved EP, DPP, or DOCD when you propose to conduct activities on your lease(s) or unit that require approval of a license or permit which is not described in your approved EP, DPP, or DOCD. These types of changes are called supplemental OCS plans.
§ 250.284 How will MMS require revisions to the approved EP, DPP, or DOCD?
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(a) Periodic review. The Regional Supervisor will periodically review the activities you conduct under your approved EP, DPP, or DOCD and may require you to submit updated information on your activities. The frequency and extent of this review will be based on the significance of any changes in available information and onshore or offshore conditions affecting, or affected by, the activities in your approved EP, DPP, or DOCD.
(b) Results of review. The Regional Supervisor may require you to revise your approved EP, DPP, or DOCD based on this review. In such cases, the Regional Supervisor will inform you of the reasons for the decision.
§ 250.285 How do I submit revised and supplemental EPs, DPPs, and DOCDs?
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(a) Submittal. You must submit to the Regional Supervisor any revisions and supplements to approved EPs, DPPs, or DOCDs for approval, whether you initiate them or the Regional Supervisor orders them.
(b) Information. Revised and supplemental EPs, DPPs, and DOCDs need include only information related to or affected by the proposed changes, including information on changes in expected environmental impacts.
(c) Procedures. All supplemental EPs, DPPs, and DOCDs, and those revised EPs, DPPs, and DOCDs that the Regional Supervisor determines are likely to result in a significant change in the impacts previously identified and evaluated, are subject to all of the procedures under §250.231 through §250.235 for EPs and §250.266 through §250.274 for DPPs and DOCDs.
Deepwater Operations Plans (DWOP)
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§ 250.286 What is a DWOP?
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(a) A DWOP is a plan that provides sufficient information for MMS to review a deepwater development project, and any other project that uses non-conventional production or completion technology, from a total system approach. The DWOP does not replace, but supplements other submittals required by the regulations such as Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents. MMS will use the information in your DWOP to determine whether the project will be developed in an acceptable manner, particularly with respect to operational safety and environmental protection issues involved with non-conventional production or completion technology.
(b) The DWOP process consists of two parts: a Conceptual Plan and the DWOP. Section 250.289 prescribes what the Conceptual Plan must contain, and §250.292 prescribes what the DWOP must contain.
§ 250.287 For what development projects must I submit a DWOP?
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You must submit a DWOP for each development project in which you will use non-conventional production or completion technology, regardless of water depth. If you are unsure whether MMS considers the technology of your project non-conventional, you must contact the Regional Supervisor for guidance.
§ 250.288 When and how must I submit the Conceptual Plan?
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You must submit four copies, or one hard copy and one electronic version, of the Conceptual Plan to the Regional Director after you have decided on the general concept(s) for development and before you begin engineering design of the well safety control system or subsea production systems to be used after well completion.
§ 250.289 What must the Conceptual Plan contain?
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In the Conceptual Plan, you must explain the general design basis and philosophy that you will use to develop the field. You must include the following information:
(a) An overview of the development concept(s);
(b) A well location plat;
(c) The system control type (i.e., direct hydraulic or electro-hydraulic); and
(d) The distance from each of the wells to the host platform.
§ 250.290 What operations require approval of the Conceptual Plan?
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You may not complete any production well or install the subsea wellhead and well safety control system (often called the tree) before MMS has approved the Conceptual Plan.
§ 250.291 When and how must I submit the DWOP?
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You must submit four copies, or one hard copy and one electronic version, of the DWOP to the Regional Director after you have substantially completed safety system design and before you begin to procure or fabricate the safety and operational systems (other than the tree), production platforms, pipelines, or other parts of the production system.
§ 250.292 What must the DWOP contain?
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You must include the following information in your DWOP:
(a) A description and schematic of the typical wellbore, casing, and completion;
(b) Structural design, fabrication, and installation information for each surface system, including host facilities;
(c) Design, fabrication, and installation information on the mooring systems for each surface system;
(d) Information on any active stationkeeping system(s) involving thrusters or other means of propulsion used with a surface system;
(e) Information concerning the drilling and completion systems;
(f) Design and fabrication information for each riser system (e.g., drilling, workover, production, and injection);
(g) Pipeline information;
(h) Information about the design, fabrication, and operation of an offtake system for transferring produced hydrocarbons to a transport vessel;
(i) Information about subsea wells and associated systems that constitute all or part of a single project development covered by the DWOP;
(j) Flow schematics and Safety Analysis Function Evaluation (SAFE) charts (API RP 14C, subsection 4.3c, incorporated by reference in §250.198) of the production system from the Surface Controlled Subsurface Safety Valve (SCSSV) downstream to the first item of separation equipment;
(k) A description of the surface/subsea safety system and emergency support systems to include a table that depicts what valves will close, at what times, and for what events or reasons;
(l) A general description of the operating procedures, including a table summarizing the curtailment of production and offloading based on operational considerations;
(m) A description of the facility installation and commissioning procedure;
(n) A discussion of any new technology that affects hydrocarbon recovery systems; and
(o) A list of any alternate compliance procedures or departures for which you anticipate requesting approval.
§ 250.293 What operations require approval of the DWOP?
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You may not begin production until MMS approves your DWOP.
§ 250.294 May I combine the Conceptual Plan and the DWOP?
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If your development project meets the following criteria, you may submit a combined Conceptual Plan/DWOP on or before the deadline for submitting the Conceptual Plan.
(a) The project is located in water depths of less than 400 meters (1,312 feet); and
(b) The project is similar to projects involving non-conventional production or completion technology for which you have obtained approval previously.
§ 250.295 When must I revise my DWOP?
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You must revise either the Conceptual Plan or your DWOP to reflect changes in your development project that materially alter the facilities, equipment, and systems described in your plan. You must submit the revision within 60 days after any material change to the information required for that part of your plan.
Conservation Information Documents (CID)
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§ 250.296 When and how must I submit a CID or a revision to a CID?
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(a) You must submit one original and two copies of a CID to the appropriate OCS Region at the same time you first submit your DOCD or DPP for any development of a lease or leases located in water depths greater than 400 meters (1,312 feet). You must also submit a CID for a Supplemental DOCD or DPP when requested by the Regional Supervisor.
(b) If you decide not to develop a reservoir you committed to develop in your CID, you must submit one original and two copies of a revision to the CID to the appropriate OCS Region. The revision to the CID must be submitted within 14 calendar days after making your decision not to develop the reservoir and before the reservoir is bypassed. The Regional Supervisor will approve or disapprove any such revision to the original CID. If the Regional Supervisor disapproves the revision, you must develop the reservoir as described in the original CID.
§ 250.297 What information must a CID contain?
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(a) You must base the CID on wells drilled before your CID submittal, that define the extent of the reservoirs. You must notify MMS of any well that is drilled to total depth during the CID evaluation period and you may be required to update your CID.
(b) You must include all of the following information if available. Information must be provided for each hydrocarbon-bearing reservoir that is penetrated by a well that would meet the producibility requirements of §250.115 or §250.116:
(1) General discussion of the overall development of the reservoir;
(2) Summary spreadsheets of well log data and reservoir parameters (i.e., sand tops and bases, fluid contacts, net pay, porosity, water saturations, pressures, formation volume factor);
(3) Appropriate well logs, including digital well log (i.e., gamma ray, resistivity, neutron, density, sonic, caliper curves) curves in an acceptable digital format;
(4) Sidewall core/whole core and pressure-volume-temperature analysis;
(5) Structure maps, with the existing and proposed penetration points and subsea depths for all wells penetrating the reservoirs, fluid contacts (or the lowest or highest known levels in the absence of actual contacts), reservoir boundaries, and the scale of the map;
(6) Interpreted structural cross sections and corresponding interpreted seismic lines or block diagrams, as necessary, that include all current wellbores and planned wellbores on the leases or units to be developed, the reservoir boundaries, fluid contacts, depth scale, stratigraphic positions, and relative biostratigraphic ages;
(7) Isopach maps of each reservoir showing the net feet of pay for each well within the reservoir identified at the penetration point, along with the well name, labeled contours, and scale;
(8) Estimates of original oil and gas in-place and anticipated recoverable oil and gas reserves, all reservoir parameters, and risk factors and assumptions;
(9) Plat map at the same scale as the structure maps with existing and proposed well paths, as well as existing and proposed penetrations;
(10) Wellbore schematics indicating proposed perforations;
(11) Proposed wellbore utility chart showing all existing and proposed wells, with proposed completion intervals indicated for each borehole;
(12) Appropriate pressure data, specified by date, and whether estimated or measured;
(13) Description of reservoir development strategies;
(14) Description of the enhanced recovery practices you will use or, if you do not plan to use such practices, an explanation of the methods you considered and reasons you do not intend to use them;
(15) For each reservoir you do not intend to develop:
(i) A statement explaining the reason(s) you will not develop the reservoir, and
(ii) Economic justification, including costs, recoverable reserve estimate, production profiles, and pricing assumptions; and
(16) Any other appropriate data you used in performing your reservoir evaluations and preparing your reservoir development strategies.
§ 250.298 How long will MMS take to evaluate and make a decision on the CID?
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(a) The Regional Supervisor will make a decision within 150 calendar days of receiving your CID. If MMS does not act within 150 calendar days, your CID is considered approved.
(b) MMS may suspend the 150-calendar-day evaluation period if there is missing, inconclusive, or inaccurate data, or when a well reaches total depth during the evaluation period. MMS may also suspend the evaluation period when a well penetrating a hydrocarbon-bearing structure reaches total depth during the evaluation period and the data from that well is needed for the CID. You will receive written notification from the Regional Supervisor describing the additional information that is needed, and the evaluation period will resume once MMS receives the requested information.
(c) The Regional Supervisor will approve or deny your CID request based on your commitment to develop economically producible reservoirs according to sound conservation, engineering, and economic practices.
§ 250.299 What operations require approval of the CID?
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You may not begin production before you receive MMS approval of the CID.
Subpart C—Pollution Prevention and Control
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§ 250.300 Pollution prevention.
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(a) During the exploration, development, production, and transportation of oil and gas or sulphur, the lessee shall take measures to prevent unauthorized discharge of pollutants into the offshore waters. The lessee shall not create conditions that will pose unreasonable risk to public health, life, property, aquatic life, wildlife, recreation, navigation, commercial fishing, or other uses of the ocean.
(1) When pollution occurs as a result of operations conducted by or on behalf of the lessee and the pollution damages or threatens to damage life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment, the control and removal of the pollution to the satisfaction of the District Supervisor shall be at the expense of the lessee. Immediate corrective action shall be taken in all cases where pollution has occurred. Corrective action shall be subject to modification when directed by the District Supervisor.
(2) If the lessee fails to control and remove the pollution, the Director, in cooperation with other appropriate Agencies of Federal, State, and local governments, or in cooperation with the lessee, or both, shall have the right to control and remove the pollution at the lessee's expense. Such action shall not relieve the lessee of any responsibility provided for by law.
(b)(1) The District Supervisor may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Supervisor may also restrict the use of components which could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Supervisor.
(2) Approval of the method of disposal of drill cuttings, sand, and other well solids shall be obtained from the District Supervisor.
(3) All hydrocarbon-handling equipment for testing and production such as separators, tanks, and treaters shall be designed, installed, and operated to prevent pollution. Maintenance or repairs which are necessary to prevent pollution of offshore waters shall be undertaken immediately.
(4) Curbs, gutters, drip pans, and drains shall be installed in deck areas in a manner necessary to collect all contaminants not authorized for discharge. Oil drainage shall be piped to a properly designed, operated, and maintained sump system which will automatically maintain the oil at a level sufficient to prevent discharge of oil into offshore waters. All gravity drains shall be equipped with a water trap or other means to prevent gas in the sump system from escaping through the drains. Sump piles shall not be used as processing devices to treat or skim liquids but may be used to collect treated-produced water, treated-produced sand, or liquids from drip pans and deck drains and as a final trap for hydrocarbon liquids in the event of equipment upsets. Improperly designed, operated, or maintained sump piles which do not prevent the discharge of oil into offshore waters shall be replaced or repaired.
(5) On artificial islands, all vessels containing hydrocarbons shall be placed inside an impervious berm or otherwise protected to contain spills. Drainage shall be directed away from the drilling rig to a sump. Drains and sumps shall be constructed to prevent seepage.
(6) Disposal of equipment, cables, chains, containers, or other materials into offshore waters is prohibited.
(c) Materials, equipment, tools, containers, and other items used in the Outer Continental Shelf (OCS) which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows:
(1) All loose material, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use and in a marked container before transport over offshore waters;
(2) All cable, chain, or wire segments shall be recovered after use and securely stored until suitable disposal is accomplished;
(3) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over offshore waters; and
(4) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they may be exposed.
(d) Any of the items described in paragraph (c) of this section that are lost overboard shall be recorded on the facility's daily operations report, as appropriate, and reported to the District Supervisor.
[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32099, July 15, 1991. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.301 Inspection of facilities.
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(a) Drilling and production facilities shall be inspected daily or at intervals approved or prescribed by the District Supervisor to determine if pollution is occurring. Necessary maintenance or repairs shall be made immediately. Records of such inspections and repairs shall be maintained at the facility or at a nearby manned facility for 2 years.
[53 FR 10690, Apr. 1, 1988, as amended at 62 FR 13996, Mar. 25, 1997. Redesignated at 63 FR 29479, May 29, 1998]
§ 250.302 Definitions concerning air quality.
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For purposes of §§250.303 and 250.304 of this part:
Air pollutant means any combination of agents for which the Environmental Protection Agency (EPA) has established, pursuant to section 109 of the Clean Air Act, national primary or secondary ambient air quality standards.
Attainment area means, for any air pollutant, an area which is shown by monitored data or which is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) not to exceed any primary or secondary ambient air quality standards established by EPA.
Best available control technology (BACT) means an emission limitation based on the maximum degree of reduction for each air pollutant subject to regulation, taking into account energy, environmental and economic impacts, and other costs. The BACT shall be verified on a case-by-case basis by the Regional Supervisor and may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant.
Emission offsets means emission reductions obtained from facilities, either onshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan or Development and Production Plan.
Existing facility is an OCS facility described in an Exploration Plan or a Development and Production Plan submitted or approved prior to June 2, 1980.
Facility means any installation or device permanently or temporarily attached to the seabed which is used for exploration, development, and production activities for oil, gas, or sulphur and which emits or has the potential to emit any air pollutant from one or more sources. All equipment directly associated with the installation or device shall be considered part of a single facility if the equipment is dependent on, or affects the processes of, the installation or device. During production, multiple installations or devices will be considered to be a single facility if the installations or devices are directly related to the production of oil, gas, or sulphur at a single site. Any vessel used to transfer production from an offshore facility shall be considered part of the facility while physically attached to it.
Nonattainment area means, for any air pollutant, an area which is shown by monitored data or which is calculated by air quality modeling (or other methods determined by the Administrator of EPA to be reliable) to exceed any primary or secondary ambient air quality standard established by EPA.
Projected emissions means emissions, either controlled or uncontrolled, from a source(s).
Source means an emission point. Several sources may be included within a single facility.
Temporary facility means activities associated with the construction of platforms offshore or with facilities related to exploration for or development of offshore oil and gas resources which are conducted in one location for less than 3 years.
Volatile organic compound (VOC) means any organic compound which is emitted to the atmosphere as a vapor. The unreactive compounds are exempt from the above definition.
[53 FR 10690, Apr. 1, 1988, as amended at 56 FR 32100, July 15, 1991. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998]
§ 250.303 Facilities described in a new or revised Exploration Plan or Development and Production Plan.
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(a) New plans. All Exploration Plans and Development and Production Plans shall include the information required to make the necessary findings under paragraphs (d) through (i) of this section, and the lessee shall comply with the requirements of this section as necessary.
(b) Applicability of §250.303 to existing facilities. (1) The Regional Supervisor may review any Exploration Plan or Development and Production Plan to determine whether any facility described in the plan should be subject to review under this section and has the potential to significantly affect the air quality of an onshore area. To make these decisions, the Regional Supervisor shall consider the distance of the facility from shore, the size of the facility, the number of sources planned for the facility and their operational status, and the air quality status of the onshore area.
(2) For a facility identified by the Regional Supervisor in paragraph (b)(1) of this section, the Regional Supervisor shall require the lessee to refer to the information required in §250.218 or §250.249 of this part and to submit only that information required to make the necessary findings under paragraphs (d) through (i) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(c) Revised facilities. All revised Exploration Plans and Development and Production Plans shall include the information required to make the necessary findings under paragraphs (d) through (i) of this section. The lessee shall comply with the requirements of this section as necessary.
(d) Exemption formulas. To determine whether a facility described in a new, modified, or revised Exploration Plan or Development and Production Plan is exempt from further air quality review, the lessee shall use the highest annual-total amount of emissions from the facility for each air pollutant calculated in §250.249(a) or §250.218(a) of this part and compare these emissions to the emission exemption amount “E” for each air pollutant calculated using the following formulas: E=3400D2/3 for carbon monoxide (CO); and E=33.3D for total suspended particulates (TSP), sulphur dioxide (SO2), nitrogen oxides (NOX), and VOC (where E is the emission exemption amount expressed in tons per year, and D is the distance of the proposed facility from the closest onshore area of a State expressed in statute miles). If the amount of these projected emissions is less than or equal to the emission exemption amount “E” for the air pollutant, the facility is exempt from further air quality review required under paragraphs (e) through (i) of this section.
(e) Significance levels. For a facility not exempt under paragraph (d) of this section for air pollutants other than VOC, the lessee shall use an approved air quality model to determine whether the projected emissions of those air pollutants from the facility result in an onshore ambient air concentration above the following significance levels:
Significance Levels: Air pollutant concentrations (µg/m\3\)
------------------------------------------------------------------------
Averaging time (hours)
Air pollutant -----------------------------
Annual 24 8 3 1
------------------------------------------------------------------------
SO2....................................... 1 5 ... 25 ......
TSP....................................... 1 5 ... .. ......
NO2....................................... 1 .. ... .. ......
CO........................................ ....... .. 500 .. 2,000
------------------------------------------------------------------------
(f) Significance determinations. (1) The projected emissions of any air pollutant other than VOC from any facility which result in an onshore ambient air concentration above the significance level determined under paragraph (e) of this section for that air pollutant, shall be deemed to significantly affect the air quality of the onshore area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (d) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(g) Controls required. (1) The projected emissions of any air pollutant other than VOC from any facility, except a temporary facility, which significantly affect the quality of a nonattainment area, shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore offsets.
(2) The projected emissions of any air pollutant other than VOC from any facility which significantly affect the air quality of an attainment or unclassifiable area shall be reduced through the application of BACT.
(i) Except for temporary facilities, the lessee also shall use an approved air quality model to determine whether the emissions of TSP or SO2 that remain after the application of BACT cause the following maximum allowable increases over the baseline concentrations established in 40 CFR 52.21 to be exceeded in the attainment or unclassifiable area:
Maximum allowable concentration increases (µg/m\3\)
------------------------------------------------------------------------
Averaging times
--------------------------
Air pollutant Annual
mean 24-hour 3-hour
\1\ maximum maximum
------------------------------------------------------------------------
Class I:
TSP........................................ 5 10 .......
SO2........................................ 2 5 25
Class II:
TSP........................................ 19 37 .......
SO2........................................ 20 91 512
Class III:
TSP........................................ 37 75 .......
SO2........................................ 40 182 700
------------------------------------------------------------------------
\1\ For TSP_geometric; For SO2_arithmetric.
No concentration of an air pollutant shall exceed the concentration permitted under the national secondary ambient air quality standard or the concentration permitted under the national primary air quality standard, whichever concentration is lowest for the air pollutant for the period of exposure. For any period other than the annual period, the applicable maximum allowable increase may be exceeded during one such period per year at any one onshore location.
(ii) If the maximum allowable increases are exceeded, the lessee shall apply whatever additional emission controls are necessary to reduce or offset the remaining emissions of TSP or SO2 so that concentrations in the onshore ambient air of an attainment or unclassifiable area do not exceed the maximum allowable increases.
(3)(i) The projected emissions of VOC from any facility, except a temporary facility, which significantly affect the onshore air quality of a nonattainment area shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore offsets.
(ii) The projected emissions of VOC from any facility which significantly affect the onshore air quality of an attainment area shall be reduced through the application of BACT.
(4)(i) If projected emissions from a facility significantly affect the onshore air quality of both a nonattainment and an attainment or unclassifiable area, the regulatory requirements applicable to projected emissions significantly affecting a nonattainment area shall apply.
(ii) If projected emissions from a facility significantly affect the onshore air quality of more than one class of attainment area, the lessee must reduce projected emissions to meet the maximum allowable increases specified for each class in paragraph (g)(2)(i) of this section.
(h) Controls required on temporary facilities. The lessee shall apply BACT to reduce projected emissions of any air pollutant from a temporary facility which significantly affect the air quality of an onshore area of a State.
(i) Emission offsets. When emission offsets are to be obtained, the lessee must demonstrate that the offsets are equivalent in nature and quantity to the projected emissions that must be reduced after the application of BACT; a binding commitment exists between the lessee and the owner or owners of the source or sources; the appropriate air quality control jurisdiction has been notified of the need to revise the State Implementation Plan to include the information regarding the offsets; and the required offsets come from sources which affect the air quality of the area significantly affected by the lessee's offshore operations.
(j) Review of facilities with emissions below the exemption amount. If, during the review of a new, modified, or revised Exploration Plan or Development and Production Plan, the Regional Supervisor determines or an affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to submit additional information to determine whether emission control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality of an onshore area of the State.
(k) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional Supervisor, emissions from the facility. The lessee shall submit this information monthly in a manner and form approved or prescribed by the Regional Supervisor.
(l) Collection of meteorological data. The Regional Supervisor may require the lessee to collect, for a period of time and in a manner approved or prescribed by the Regional Supervisor, and submit meteorological data from a facility.
[53 FR 10690, Apr. 1, 1988; 53 FR 19856, May 31, 1988; 53 FR 26067, July 11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 70 FR 51518, Aug. 30, 2005]
§ 250.304 Existing facilities.
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(a) Process leading to review of an existing facility. (1) An affected State may request that the Regional Supervisor supply basic emission data from existing facilities when such data are needed for the updating of the State's emission inventory. In submitting the request, the State must demonstrate that similar offshore and onshore facilities in areas under the State's jurisdiction are also included in the emission inventory.
(2) The Regional Supervisor may require lessees of existing facilities to submit basic emission data to a State submitting a request under paragraph (a)(1) of this section.
(3) The State submitting a request under paragraph (a)(1) of this section may submit information from its emission inventory which indicates that emissions from existing facilities may be significantly affecting the air quality of the onshore area of the State. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the facility is not significantly affecting the air quality of the State.
(4) The Regional Supervisor shall evaluate the information submitted under paragraph (a)(3) of this section and shall determine, based on the basic emission data, available meteorological data, and the distance of the facility or facilities from the onshore area, whether any existing facility has the potential to significantly affect the air quality of the onshore area of the State.
(5) If the Regional Supervisor determines that no existing facility has the potential to significantly affect the air quality of the onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall notify the State of and explain the reasons for this finding.
(6) If the Regional Supervisor determines that an existing facility has the potential to significantly affect the air quality of an onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall require the lessee to refer to the information requirements under §250.218 or 250.249 of this part and submit only that information required to make the necessary findings under paragraphs (b) through (e) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(b) Exemption formulas. To determine whether an existing facility is exempt from further air quality review, the lessee shall use the highest annual total amount of emissions from the facility for each air pollutant calculated in §250.218(a) or 250.249(a) of this part and compare these emissions to the emission exemption amount “E” for each air pollutant calculated using the following formulas: E=3400D2/3 for CO; and E=33.3D for TSP, SO2, NOX, and VOC (where E is the emission exemption amount expressed in tons per year, and D is the distance of the facility from the closest onshore area of the State expressed in statute miles). If the amount of projected emissions is less than or equal to the emission exemption amount “E” for the air pollutant, the facility is exempt for that air pollutant from further air quality review required under paragraphs (c) through (e) of this section.
(c) Significance levels. For a facility not exempt under paragraph (b) of this section for air pollutants other than VOC, the lessee shall use an approved air quality model to determine whether projected emissions of those air pollutants from the facility result in an onshore ambient air concentration above the following significance levels:
Significance Levels: Air Pollutant Concentrations (µG/M\3\)
------------------------------------------------------------------------
Averaging time (hours)
Air pollutant -----------------------------
Annual 24 8 3 1
------------------------------------------------------------------------
SO2....................................... 1 5 ... 25 ......
TSP....................................... 1 5 ... .. ......
NO2....................................... 1 .. ... .. ......
CO........................................ ....... .. 500 .. 2,000
------------------------------------------------------------------------
(d) Significance determinations. (1) The projected emissions of any air pollutant other than VOC from any facility which result in an onshore ambient air concentration above the significance levels determined under paragraph (c) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for that air pollutant.
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (b) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(e) Controls required. (1) The projected emissions of any air pollutant which significantly affect the air quality of an onshore area shall be reduced through the application of BACT.
(2) The lessee shall submit a compliance schedule for the application of BACT. If it is necessary to cease operations to allow for the installation of emission controls, the lessee may apply for a suspension of operations under the provisions of §250.174 of this part.
(f) Review of facilities with emissions below the exemption amount. If, during the review of the information required under paragraph (a)(6) of this section, the Regional Supervisor determines or an affected State submits information to the Regional Supervisor which demonstrates, in the judgment of the Regional Supervisor, that projected emissions from an otherwise exempt facility will, either individually or in combination with other facilities in the area, significantly affect the air quality of an onshore area, then the Regional Supervisor shall require the lessee to submit additional information to determine whether control measures are necessary. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the exempt facility is not significantly affecting the air quality of an onshore area of the State.
(g) Emission monitoring requirements. The lessee shall monitor, in a manner approved or prescribed by the Regional Supervisor, emissions from the facility following the installation of emission controls. The lessee shall submit this information monthly in a manner and form approved or prescribed by the Regional Supervisor.
(h) Collection of meteorological data. The Regional Supervisor may require the lessee to collect, for a period of time and in a manner approved or prescribed by the Regional Supervisor, and submit meteorological data from a facility.
[53 FR 10690, Apr. 1, 1988; 53 FR 26067, July 11, 1988. Redesignated and amended at 63 FR 29479, 29485, May 29, 1998; 64 FR 72794, Dec. 28, 1999; 70 FR 51519, Aug. 30, 2005]
Subpart D—Oil and Gas Drilling Operations
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General Requirements
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§ 250.400 Who is subject to the requirements of this subpart?
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The requirements of this subpart apply to lessees, operating rights owners, operators, and their contractors and subcontractors.
[68 FR 8423, Feb. 20, 2003]
§ 250.401 What must I do to keep wells under control?
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You must take necessary precautions to keep wells under control at all times. You must:
(a) Use the best available and safest drilling technology to monitor and evaluate well conditions and to minimize the potential for the well to flow or kick;
(b) Have a person onsite during drilling operations who represents your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a member of the drilling crew maintains continuous surveillance on the rig floor from the beginning of drilling operations until the well is completed or abandoned, unless you have secured the well with blowout preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subpart O; and
(e) Use and maintain equipment and materials necessary to ensure the safety and protection of personnel, equipment, natural resources, and the environment.
[68 FR 8423, Feb. 20, 2003]
§ 250.402 When and how must I secure a well?
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Whenever you interrupt drilling operations, you must install a downhole safety device, such as a cement plug, bridge plug, or packer. You must install the device at an appropriate depth within a properly cemented casing string or liner.
(a) Among the events that may cause you to interrupt drilling operations are:
(1) Evacuation of the drilling crew;
(2) Inability to keep the drilling rig on location; or
(3) Repair to major drilling or well-control equipment.
(b) For floating drilling operations, the District Supervisor may approve the use of blind or blind-shear rams or pipe rams and an inside BOP if you don't have time to install a downhole safety device or if special circumstances occur.
[68 FR 8423, Feb. 20, 2003]
§ 250.403 What drilling unit movements must I report?
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(a) You must report the movement of all drilling units on and off drilling locations to the District Supervisor. This includes both MODU and platform rigs. You must inform the District Supervisor 24 hours before:
(1) The arrival of an MODU on location;
(2) The movement of a platform rig to a platform;
(3) The movement of a platform rig to another slot;
(4) The movement of an MODU to another slot; and
(5) The departure of an MODU from the location.
(b) You must provide the District Supervisor with the rig name, lease number, well number, and expected time of arrival or departure.
(c) In the Gulf of Mexico OCS Region, you must report drilling unit movements on form MMS–144, Rig Movement Notification Report.
[68 FR 8423, Feb. 20, 2003]
§ 250.404 What are the requirements for the crown block?
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You must have a crown block safety device that prevents the traveling block from striking the crown block. You must check the device for proper operation at least once per week and after each drill-line slipping operation and record the results of this operational check in the driller's report.
[68 FR 8423, Feb. 20, 2003]
§ 250.405 What are the safety requirements for diesel engines used on a drilling rig?
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You must equip each diesel engine with an air take device to shut down the diesel engine in the event of a runaway.
(a) For a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip the engine with either an automatic or remote manual air intake shutdown device;
(c) You do not have to equip a diesel engine with an air intake device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
[68 FR 8423, Feb. 20, 2003]
§ 250.406 What additional safety measures must I take when I conduct drilling operations on a platform that has producing wells or has other hydrocarbon flow?
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You must take the following safety measures when you conduct drilling operations on a platform with producing wells or that has other hydrocarbon flow:
(a) You must install an emergency shutdown station near the driller's console;
(b) You must shut in all producible wells located in the affected wellbay belowthe surface and at the wellhead when: (continued)