44 

SUBCHAPTER B—OFFSHORE 

PART 250—OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER 

CONTINENTAL SHELF 

Subpart A—General 

AUTHORITY AND DEFINITION OF TERMS

Sec. 

250.101 Authority and applicability. 

250.102 What does this part do? 

250.103 Where can I find more information 

about the requirements in this part? 

250.104 How may I appeal a decision made 

under BSEE regulations? 

250.105 Definitions. 

PERFORMANCE STANDARDS

250.106 What standards will the Director use 

to regulate lease operations? 

250.107 What must I do to protect health, 

safety, property, and the environment? 

250.108 What requirements must I follow for 

cranes and other material-handling 

equipment? 

250.109 What documents must I prepare and 

maintain related to welding? 

250.110 What must I include in my welding 

plan? 

250.111 Who oversees operations under my 

welding plan? 

250.112 What standards must my welding 

equipment meet? 

250.113 What procedures must I follow when 

welding? 

250.114 How must I install and operate electrical equipment? 

250.115–250.117 [Reserved] 

250.118 Will BSEE approve gas injection? 

250.119 [Reserved] 

250.120 How does injecting, storing, or treating gas affect my royalty payments? 

250.121 What happens when the reservoir 

contains both original gas in place and 

injected gas? 

250.122 What effect does subsurface storage 

have on the lease term? 

250.123 [Reserved] 

250.124 Will BSEE approve gas injection 

into the cap rock containing a sulphur 

deposit? 

FEES

250.125 Service fees. 

250.126 Electronic payment instructions. 

INSPECTION OF OPERATIONS

250.130 Why does BSEE conduct inspections? 

250.131 Will BSEE notify me before conducting an inspection? 

250.132 What must I do when BSEE conducts 

an inspection? 

250.133 Will BSEE reimburse me for my expenses related to inspections? 

DISQUALIFICATION

250.135 What will BSEE do if my operating 

performance is unacceptable? 

250.136 How will BSEE determine if my operating performance is unacceptable? 

SPECIAL TYPES OF APPROVALS

250.140 When will I receive an oral approval? 

250.141 May I ever use alternate procedures 

or equipment? 

250.142 How do I receive approval for departures? 

250.143–250.144 [Reserved] 

250.145 How do I designate an agent or a 

local agent? 

250.146 Who is responsible for fulfilling 

leasehold obligations? 

NAMING AND IDENTIFYING FACILITIES AND

WELLS (DOES NOT INCLUDE MODUS) 

250.150 How do I name facilities and wells in 

the Gulf of Mexico Region? 

250.151 How do I name facilities in the Pacific Region? 

250.152 How do I name facilities in the Alaska Region? 

250.153 Do I have to rename an existing facility or well? 

250.154 What identification signs must I display? 

250.160–250.167 [Reserved] 

SUSPENSIONS

250.168 May operations or production be suspended? 

250.169 What effect does suspension have on 

my lease? 

250.170 How long does a suspension last? 

250.171 How do I request a suspension? 

250.172 When may the Regional Supervisor 

grant or direct an SOO or SOP? 

250.173 When may the Regional Supervisor 

direct an SOO or SOP? 

250.174 When may the Regional Supervisor 

grant or direct an SOP? 

250.175 When may the Regional Supervisor 

grant an SOO? 

250.176 Does a suspension affect my royalty 

payment? 

250.177 What additional requirements may 

the Regional Supervisor order for a suspension? 

PRIMARY LEASE REQUIREMENTS, LEASE TERM

EXTENSIONS, AND LEASE CANCELLATIONS

250.180 What am I required to do to keep my 

lease term in effect? 


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Safety & Environmental Enforcement, Interior Pt. 250 

250.181–250.185 [Reserved] 

INFORMATION AND REPORTING REQUIREMENTS

250.186 What reporting information and report forms must I submit? 

250.187 What are BSEE’s incident reporting 

requirements? 

250.188 What incidents must I report to 

BSEE and when must I report them? 

250.189 Reporting requirements for incidents requiring immediate notification. 

250.190 Reporting requirements for incidents requiring written notification. 

250.191 How does BSEE conduct incident investigations? 

250.192 What reports and statistics must I 

submit relating to a hurricane, earthquake, or other natural occurrence? 

250.193 Reports and investigations of possible violations. 

250.194 How must I protect archaeological 

resources? 

250.195 What notification does BSEE require 

on the production status of wells? 

250.196 Reimbursements for reproduction 

and processing costs. 

250.197 Data and information to be made 

available to the public or for limited inspection. 

REFERENCES

250.198 Documents incorporated by reference. 

250.199 Paperwork Reduction Act statements—information collection. 

Subpart B—Plans and Information 

GENERAL INFORMATION

250.200 Definitions. 

250.201 What plans and information must I 

submit before I conduct any activities on 

my lease or unit? 

250.202–250.203 [Reserved] 

250.204 How must I protect the rights of the 

Federal government? 

250.205 Are there special requirements if my 

well affects an adjacent property? 

POST-APPROVAL REQUIREMENTS FOR THE EP, 

DPP, AND DOCD 

250.282 Do I have to conduct post-approval 

monitoring? 

DEEPWATER OPERATIONS PLANS (DWOP) 

250.286 What is a DWOP? 

250.287 For what development projects must 

I submit a DWOP? 

250.288 When and how must I submit the 

Conceptual Plan? 

250.289 What must the Conceptual Plan contain? 

250.290 What operations require approval of 

the Conceptual Plan? 

250.291 When and how must I submit the 

DWOP? 

250.292 What must the DWOP contain? 

250.293 What operations require approval of 

the DWOP? 

250.294 May I combine the Conceptual Plan 

and the DWOP? 

250.295 When must I revise my DWOP? 

Subpart C—Pollution Prevention and 

Control 

250.300 Pollution prevention. 

250.301 Inspection of facilities. 

Subpart D—Oil and Gas Drilling Operations 

GENERAL REQUIREMENTS

250.400 Who is subject to the requirements 

of this subpart? 

250.401 What must I do to keep wells under 

control? 

250.402 When and how must I secure a well? 

250.403 What drilling unit movements must 

I report? 

250.404 What are the requirements for the 

crown block? 

250.405 What are the safety requirements for 

diesel engines used on a drilling rig? 

250.406 What additional safety measures 

must I take when I conduct drilling operations on a platform that has producing 

wells or has other hydrocarbon flow? 

250.407 What tests must I conduct to determine reservoir characteristics? 

250.408 May I use alternative procedures or 

equipment during drilling operations? 

250.409 May I obtain departures from these 

drilling requirements? 

APPLYING FOR A PERMIT TO DRILL

250.410 How do I obtain approval to drill a 

well? 

250.411 What information must I submit 

with my application? 

250.412 What requirements must the location plat meet? 

250.413 What must my description of well 

drilling design criteria address? 

250.414 What must my drilling prognosis include? 

250.415 What must my casing and cementing 

programs include? 

250.416 What must I include in the diverter 

and BOP descriptions? 

250.417 What must I provide if I plan to use 

a mobile offshore drilling unit (MODU)? 

250.418 What additional information must I 

submit with my APD? 

CASING AND CEMENTING REQUIREMENTS

250.420 What well casing and cementing requirements must I meet? 

250.421 What are the casing and cementing 

requirements by type of casing string? 

250.422 When may I resume drilling after cementing? 


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Pt. 250 30 CFR Ch. II (7–1–13 Edition) 

250.423 What are the requirements for pressure testing casing? 

250.424 What are the requirements for prolonged drilling operations? 

250.425 What are the requirements for pressure testing liners? 

250.426 What are the recordkeeping requirements for casing and liner pressure tests? 

250.427 What are the requirements for pressure integrity tests? 

250.428 What must I do in certain cementing 

and casing situations? 

DIVERTER SYSTEM REQUIREMENTS

250.430 When must I install a diverter system? 

250.431 What are the diverter design and installation requirements? 

250.432 How do I obtain a departure to diverter design and installation requirements? 

250.433 What are the diverter actuation and 

testing requirements? 

250.434 What are the recordkeeping requirements for diverter actuations and tests? 

BLOWOUT PREVENTER (BOP) SYSTEM

REQUIREMENTS

250.440 What are the general requirements 

for BOP systems and system components? 

250.441 What are the requirements for a surface BOP stack? 

250.442 What are the requirements for a 

subsea BOP system? 

250.443 What associated systems and related 

equipment must all BOP systems include? 

250.444 What are the choke manifold requirements? 

250.445 What are the requirements for kelly 

valves, inside BOPs, and drill-string safety valves? 

250.446 What are the BOP maintenance and 

inspection requirements? 

250.447 When must I pressure test the BOP 

system? 

250.448 What are the BOP pressure tests requirements? 

250.449 What additional BOP testing requirements must I meet? 

250.450 What are the recordkeeping requirements for BOP tests? 

250.451 What must I do in certain situations 

involving BOP equipment or systems? 

DRILLING FLUID REQUIREMENTS

250.455 What are the general requirements 

for a drilling fluid program? 

250.456 What safe practices must the drilling fluid program follow? 

250.457 What equipment is required to monitor drilling fluids? 

250.458 What quantities of drilling fluids are 

required? 

250.459 What are the safety requirements for 

drilling fluid-handling areas? 

OTHER DRILLING REQUIREMENTS

250.460 What are the requirements for conducting a well test? 

250.461 What are the requirements for directional and inclination surveys? 

250.462 What are the requirements for wellcontrol drills? 

250.463 Who establishes field drilling rules? 

APPLYING FOR A PERMIT TO MODIFY AND

WELL RECORDS

250.465 When must I submit an Application 

for Permit to Modify (APM) or an End of 

Operations Report to BSEE? 

250.466 What records must I keep? 

250.467 How long must I keep records? 

250.468 What well records am I required to 

submit? 

250.469 What other well records could I be 

required to submit? 

HYDROGEN SULFIDE

250.490 Hydrogen sulfide. 

Subpart E—Oil and Gas Well-Completion 

Operations 

250.500 General requirements. 

250.501 Definition. 

250.502 Equipment movement. 

250.503 Emergency shutdown system. 

250.504 Hydrogen sulfide. 

250.505 Subsea completions. 

250.506 Crew instructions. 

250.507–250.508 [Reserved] 

250.509 Well-completion structures on fixed 

platforms. 

250.510 Diesel engine air intakes. 

250.511 Traveling-block safety device. 

250.512 Field well-completion rules. 

250.513 Approval and reporting of well-completion operations. 

250.514 Well-control fluids, equipment, and 

operations. 

250.515 What BOP information must I submit? 

250.516 Blowout prevention equipment. 

250.517 Blowout preventer system tests, inspections, and maintenance. 

250.518 Tubing and wellhead equipment. 

CASING PRESSURE MANAGEMENT

250.519 What are the requirements for casing pressure management? 

250.520 How often do I have to monitor for 

casing pressure? 

250.521 When do I have to perform a casing 

diagnostic test? 

250.522 How do I manage the thermal effects 

caused by initial production on a newly 

completed or recompleted well? 

250.523 When do I have to repeat casing diagnostic testing? 


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Safety & Environmental Enforcement, Interior Pt. 250 

250.524 How long do I keep records of casing 

pressure and diagnostic tests? 

250.525 When am I required to take action 

from my casing diagnostic test? 

250.526 What do I submit if my casing diagnostic test requires action? 

250.527 What must I include in my notification of corrective action? 

250.528 What must I include in my casing 

pressure request? 

250.529 What are the terms of my casing 

pressure request? 

250.530 What if my casing pressure request 

is denied? 

250.531 When does my casing pressure request approval become invalid? 

Subpart F—Oil and Gas Well-Workover 

Operations 

250.600 General requirements. 

250.601 Definitions. 

250.602 Equipment movement. 

250.603 Emergency shutdown system. 

250.604 Hydrogen sulfide. 

250.605 Subsea workovers. 

250.606 Crew instructions. 

250.607–250.608 [Reserved] 

250.609 Well-workover structures on fixed 

platforms. 

250.610 Diesel engine air intakes. 

250.611 Traveling-block safety device. 

250.612 Field well-workover rules. 

250.613 Approval and reporting for wellworkover operations. 

250.614 Well-control fluids, equipment, and 

operations. 

250.615 What BOP information must I submit? 

250.616 Blowout prevention equipment. 

250.617 Blowout preventer system testing, 

records, and drills. 

250.618 What are my BOP inspection and 

maintenance requirements? 

250.619 Tubing and wellhead equipment. 

250.620 Wireline operations. 

Subpart G [Reserved] 

Subpart H—Oil and Gas Production Safety 

Systems 

250.800 General requirements. 

250.801 Subsurface safety devices. 

250.802 Design, installation, and operation 

of surface production-safety systems. 

250.803 Additional production system requirements. 

250.804 Production safety-system testing 

and records. 

250.805 Safety device training. 

250.806 Safety and pollution prevention 

equipment quality assurance requirements. 

250.807 Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments. 

250.808 Hydrogen sulfide. 

Subpart I—Platforms and Structures 

GENERAL REQUIREMENTS FOR PLATFORMS

250.900 What general requirements apply to 

all platforms? 

250.901 What industry standards must your 

platform meet? 

250.902 What are the requirements for platform removal and location clearance? 

250.903 What records must I keep? 

PLATFORM APPROVAL PROGRAM

250.904 What is the Platform Approval Program? 

250.905 How do I get approval for the installation, modification, or repair of my 

platform? 

250.906 What must I do to obtain approval 

for the proposed site of my platform? 

250.907 Where must I locate foundation 

boreholes? 

250.908 What are the minimum structural 

fatigue design requirements? 

PLATFORM VERIFICATION PROGRAM

250.909 What is the Platform Verification 

Program? 

250.910 Which of my facilities are subject to 

the Platform Verification Program? 

250.911 If my platform is subject to the 

Platform Verification Program, what 

must I do? 

250.912 What plans must I submit under the 

Platform Verification Program? 

250.913 When must I resubmit Platform 

Verification Program plans? 

250.914 How do I nominate a CVA? 

250.915 What are the CVA’s primary responsibilities? 

250.916 What are the CVA’s primary duties 

during the design phase? 

250.917 What are the CVA’s primary duties 

during the fabrication phase? 

250.918 What are the CVA’s primary duties 

during the installation phase? 

INSPECTION, MAINTENANCE, AND ASSESSMENT

OF PLATFORMS

250.919 What in-service inspection requirements must I meet? 

250.920 What are the BSEE requirements for 

assessment of fixed platforms? 

250.921 How do I analyze my platform for 

cumulative fatigue? 

Subpart J—Pipelines and Pipeline Rightsof-Way 

250.1000 General requirements. 

250.1001 Definitions. 

250.1002 Design requirements for DOI pipelines. 


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250.1003 Installation, testing, and repair requirements for DOI pipelines. 

250.1004 Safety equipment requirements for 

DOI pipelines. 

250.1005 Inspection requirements for DOI 

pipelines. 

250.1006 How must I decommission and take 

out of service a DOI pipeline? 

250.1007 What to include in applications. 

250.1008 Reports. 

250.1009 Requirements to obtain pipeline 

right-of-way grants. 

250.1010 General requirements for pipeline 

right-of-way holders. 

250.1011 [Reserved] 

250.1012 Required payments for pipeline 

right-of-way holders. 

250.1013 Grounds for forfeiture of pipeline 

right-of-way grants. 

250.1014 When pipeline right-of-way grants 

expire. 

250.1015 Applications for pipeline right-ofway grants. 

250.1016 Granting pipeline rights-of-way. 

250.1017 Requirements for construction 

under pipeline right-of-way grants. 

250.1018 Assignment of pipeline right-of-way 

grants. 

250.1019 Relinquishment of pipeline right-ofway grants. 

Subpart K—Oil and Gas Production 

Requirements 

GENERAL

250.1150 What are the general reservoir production requirements? 

WELL TESTS AND SURVEYS

250.1151 How often must I conduct well production tests? 

250.1152 How do I conduct well tests? 

250.1153 [Reserved] 

CLASSIFYING RESERVOIRS

250.1154–250.1155 [Reserved] 

APPROVALS PRIOR TO PRODUCTION

250.1156 What steps must I take to receive 

approval to produce within 500 feet of a 

unit or lease line? 

250.1157 How do I receive approval to 

produce gas-cap gas from an oil reservoir 

with an associated gas cap? 

250.1158 How do I receive approval to 

downhole commingle hydrocarbons? 

PRODUCTION RATES

250.1159 May the Regional Supervisor limit 

my well or reservoir production rates? 

LARING, VENTING, AND BURNING

HYDROCARBONS

250.1160 When may I flare or vent gas? 

250.1161 When may I flare or vent gas for extended periods of time? 

250.1162 When may I burn produced liquid 

hydrocarbons? 

250.1163 How must I measure gas flaring or 

venting volumes and liquid hydrocarbon 

burning volumes, and what records must 

I maintain? 

250.1164 What are the requirements for flaring or venting gas containing H2S? 

OTHER REQUIREMENTS

250.1165 What must I do for enhanced recovery operations? 

250.1166 What additional reporting is required for developments in the Alaska 

OCS Region? 

250.1167 What information must I submit 

with forms and for approvals? 

Subpart L—Oil and Gas Production Measurement, Surface Commingling, and 

Security 

250.1200 Question index table. 

250.1201 Definitions. 

250.1202 Liquid hydrocarbon measurement. 

250.1203 Gas measurement. 

250.1204 Surface commingling. 

250.1205 Site security. 

Subpart M—Unitization 

250.1300 What is the purpose of this subpart? 

250.1301 What are the requirements for unitization? 

250.1302 What if I have a competitive reservoir on a lease? 

250.1303 How do I apply for voluntary unitization? 

250.1304 How will BSEE require unitization? 

Subpart N—Outer Continental Shelf Civil 

Penalties 

OUTER CONTINENTAL SHELF LANDS ACT CIVIL

PENALTIES

250.1400 How does BSEE begin the civil penalty process? 

250.1401 Index table. 

250.1402 Definitions. 

250.1403 What is the maximum civil penalty? 

250.1404 Which violations will BSEE review 

for potential civil penalties? 

250.1405 When is a case file developed? 

250.1406 When will BSEE notify me and provide penalty information? 

250.1407 How do I respond to the letter of 

notification? 

250.1408 When will I be notified of the Reviewing Officer’s decision? 

250.1409 What are my appeal rights? 


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FEDERAL OIL AND GAS ROYALTY MANAGEMENT

ACT CIVIL PENALTIES DEFINITIONS

250.1450 What definitions apply to this subpart? 

PENALTIES AFTER A PERIOD TO CORRECT

250.1451 What may BSEE do if I violate a 

statute, regulation, order, or lease term 

relating to a Federal oil and gas lease? 

250.1452 What if I correct the violation? 

250.1453 What if I do not correct the violation? 

250.1454 How may I request a hearing on the 

record on a Notice of Noncompliance? 

250.1455 Does my request for a hearing on 

the record affect the penalties? 

250.1456 May I request a hearing on the 

record regarding the amount of a civil 

penalty if I did not request a hearing on 

the Notice of Noncompliance? 

PENALTIES WITHOUT A PERIOD TO CORRECT

250.1460 May I be subject to penalties without prior notice and an opportunity to 

correct? 

250.1461 How will BSEE inform me of violations without a period to correct? 

250.1462 How may I request a hearing on the 

record on a Notice of Noncompliance regarding violations without a period to 

correct? 

250.1463 Does my request for a hearing on 

the record affect the penalties? 

250.1464 May I request a hearing on the 

record regarding the amount of a civil 

penalty if I did not request a hearing on 

the Notice of Noncompliance? 

GENERAL PROVISIONS

250.1470 How does BSEE decide what the 

amount of the penalty should be? 

250.1471 Does the penalty affect whether I 

owe interest? 

250.1472 How will the Office of Hearings and 

Appeals conduct the hearing on the 

record? 

250.1473 How may I appeal the Administrative Law Judge’s decision? 

250.1474 May I seek judicial review of the 

decision of the Interior Board of Land 

Appeals? 

250.1475 When must I pay the penalty? 

250.1476 Can BSEE reduce my penalty once 

it is assessed? 

250.1477 How may BSEE collect the penalty? 

CRIMINAL PENALTIES

250.1480 May the United States criminally 

prosecute me for violations under Federal oil and gas leases? 

BONDING REQUIREMENTS

250.1490 What standards must my BOEMspecified surety instrument meet? 

250.1491 How will BOEM determine the 

amount of my bond or other surety instrument? 

FINANCIAL SOLVENCY REQUIREMENTS

250.1495 How do I demonstrate financial solvency? 

250.1496 How will BOEM determine if I am 

financially solvent? 

250.1497 When will BOEM monitor my financial solvency? 

Subpart O—Well Control and Production 

Safety Training 

250.1500 Definitions. 

250.1501 What is the goal of my training program? 

250.1503 What are my general responsibilities for training? 

250.1504 May I use alternative training 

methods? 

250.1505 Where may I get training for my 

employees? 

250.1506 How often must I train my employees? 

250.1507 How will BSEE measure training 

results? 

250.1508 What must I do when BSEE administers written or oral tests? 

250.1509 What must I do when BSEE administers or requires hands-on, simulator, or 

other types of testing? 

250.1510 What will BSEE do if my training 

program does not comply with this subpart? 

Subpart P—Sulphur Operations 

250.1600 Performance standard. 

250.1601 Definitions. 

250.1602 Applicability. 

250.1603 Determination of sulphur deposit. 

250.1604 General requirements. 

250.1605 Drilling requirements. 

250.1606 Control of wells. 

250.1607 Field rules. 

250.1608 Well casing and cementing. 

250.1609 Pressure testing of casing. 

250.1610 Blowout preventer systems and system components. 

250.1611 Blowout preventer systems tests, 

actuations, inspections, and maintenance. 

250.1612 Well-control drills. 

250.1613 Diverter systems. 

250.1614 Mud program. 

250.1615 Securing of wells. 

250.1616 Supervision, surveillance, and 

training. 

250.1617 Application for permit to drill. 

250.1618 Application for permit to modify. 

250.1619 Well records. 

250.1620 Well-completion and well-workover 

requirements. 

250.1621 Crew instructions. 


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250.1622 Approvals and reporting of wellcompletion and well-workover operations. 

250.1623 Well-control fluids, equipment, and 

operations. 

250.1624 Blowout prevention equipment. 

250.1625 Blowout preventer system testing, 

records, and drills. 

250.1626 Tubing and wellhead equipment. 

250.1627 Production requirements. 

250.1628 Design, installation, and operation 

of production systems. 

250.1629 Additional production and fuel gas 

system requirements. 

250.1630 Safety-system testing and records. 

250.1631 Safety device training. 

250.1632 Production rates. 

250.1633 Production measurement. 

250.1634 Site security. 

Subpart Q—Decommissioning Activities 

GENERAL

250.1700 What do the terms ‘‘decommissioning’’, ‘‘obstructions’’, and ‘‘facility’’ 

mean? 

250.1701 Who must meet the decommissioning obligations in this subpart? 

250.1702 When do I accrue decommissioning 

obligations? 

250.1703 What are the general requirements 

for decommissioning? 

250.1704 When must I submit decommissioning applications and reports? 

250.1705 What BOP information must I submit? 

250.1706 What are the requirements for 

blowout prevention equipment? 

250.1707 What are the requirements for 

blowout preventer system testing, 

records, and drills? 

250.1708 What are my BOP inspection and 

maintenance requirements? 

250.1709 What are my well-control fluid requirements? 

PERMANENTLY PLUGGING WELLS

250.1710 When must I permanently plug all 

wells on a lease? 

250.1711 When will BSEE order me to permanently plug a well? 

250.1712 What information must I submit 

before I permanently plug a well or zone? 

250.1713 Must I notify BSEE before I begin 

well plugging operations? 

250.1714 What must I accomplish with well 

plugs? 

250.1715 How must I permanently plug a 

well? 

250.1716 To what depth must I remove 

wellheads and casings? 

250.1717 After I permanently plug a well, 

what information must I submit? 

TEMPORARY ABANDONED WELLS

250.1721 If I temporarily abandon a well that 

I plan to re-enter, what must I do? 

250.1722 If I install a subsea protective device, what requirements must I meet? 

250.1723 What must I do when it is no longer 

necessary to maintain a well in temporary abandoned status? 

REMOVING PLATFORMS AND OTHER FACILITIES

250.1725 When do I have to remove platforms 

and other facilities? 

250.1726 When must I submit an initial platform removal application and what must 

it include? 

250.1727 What information must I include in 

my final application to remove a platform or other facility? 

250.1728 To what depth must I remove a 

platform or other facility? 

250.1729 After I remove a platform or other 

facility, what information must I submit? 

250.1730 When might BSEE approve partial 

structure removal or toppling in place? 

250.1731 Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE? 

SITE CLEARANCE FOR WELLS, PLATFORMS, AND

OTHER FACILITIES

250.1740 How must I verify that the site of a 

permanently plugged well, removed platform, or other removed facility is clear 

of obstructions? 

250.1741 If I drag a trawl across a site, what 

requirements must I meet? 

250.1742 What other methods can I use to 

verify that a site is clear? 

250.1743 How do I certify that a site is clear 

of obstructions? 

PIPELINE DECOMMISSIONING

250.1750 When may I decommission a pipeline in place? 

250.1751 How do I decommission a pipeline 

in place? 

250.1752 How do I remove a pipeline? 

250.1753 After I decommission a pipeline, 

what information must I submit? 

250.1754 When must I remove a pipeline decommissioned in place? 

Subpart R [Reserved] 

Subpart S—Safety and Environmental 

Management Systems (SEMS) 

250.1900 Must I have a SEMS program? 

250.1901 What is the goal of my SEMS program? 

250.1902 What must I include in my SEMS 

program? 

250.1903 Acronyms and definitions. 

250.1904 Special instructions. 

250.1905–250.1908 [Reserved] 


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Safety & Environmental Enforcement, Interior § 250.102 

250.1909 What are management’s general responsibilities for the SEMS program? 

250.1910 What safety and environmental information is required? 

250.1911 What hazards analysis criteria 

must my SEMS program meet? 

250.1912 What criteria for management of 

change must my SEMS program meet? 

250.1913 What criteria for operating procedures must my SEMS program meet? 

250.1914 What criteria must be documented 

in my SEMS program for safe work practices and contractor selection? 

250.1915 What training criteria must be in 

my SEMS program? 

250.1916 What criteria for mechanical integrity must my SEMS program meet? 

250.1917 What criteria for pre-startup review 

must be in my SEMS program? 

250.1918 What criteria for emergency response and control must be in my SEMS 

program? 

250.1919 What criteria for investigation of 

incidents must be in my SEMS program? 

250.1920 What are the auditing requirements 

for my SEMS program? 

250.1921 What qualifications must the ASP 

meet? 

250.1922 What qualifications must an AB 

meet? 

250.1923 [Reserved] 

250.1924 How will BSEE determine if my 

SEMS program is effective? 

250.1925 May BSEE direct me to conduct additional audits? 

250.1926 [Reserved] 

250.1927 What happens if BSEE finds shortcomings in my SEMS program? 

250.1928 What are my recordkeeping and 

documentation requirements? 

250.1929 What are my responsibilities for 

submitting OCS performance measure 

data? 

250.1930 What must be included in my SEMS 

program for SWA? 

250.1931 What must be included in my SEMS 

program for UWA? 

250.1932 What are my EPP requirements? 

250.1933 What procedures must be included 

for reporting unsafe working conditions? 

AUTHORITY: 30 U.S.C. 1751, 31 U.S.C. 9701, 43 

U.S.C. 1334. 

SOURCE: 76 FR 64462, Oct. 18, 2011, unless 

otherwise noted. 

EDITORIAL NOTE: Nomenclature changes to 

part 250 appear at 77 FR 50891, Aug. 22, 2012. 

Subpart A—General 

AUTHORITY AND DEFINITION OF TERMS

§ 250.101 Authority and applicability. 

The Secretary of the Interior (Secretary) authorized the Bureau of Safety and Environmental Enforcement 

(BSEE) to regulate oil, gas, and sulphur exploration, development, and 

production operations on the Outer 

Continental Shelf (OCS). Under the 

Secretary’s authority, the Director requires that all operations: 

(a) Be conducted according to the 

OCS Lands Act (OCSLA), the regulations in this part, BSEE orders, the 

lease or right-of-way, and other applicable laws, regulations, and amendments; and 

(b) Conform to sound conservation 

practice to preserve, protect, and develop mineral resources of the OCS to: 

(1) Make resources available to meet 

the Nation’s energy needs; 

(2) Balance orderly energy resource 

development with protection of the 

human, marine, and coastal environments; 

(3) Ensure the public receives a fair 

and equitable return on the resources 

of the OCS; 

(4) Preserve and maintain free enterprise competition; and 

(5) Minimize or eliminate conflicts 

between the exploration, development, 

and production of oil and natural gas 

and the recovery of other resources. 

§ 250.102 What does this part do? 

(a) This part 250 contains the regulations of the BSEE Offshore program 

that govern oil, gas, and sulphur exploration, development, and production 

operations on the OCS. When you conduct operations on the OCS, you must 

submit requests, applications, and notices, or provide supplemental information for BSEE approval. 

(b) The following table of general references shows where to look for information about these processes. 

TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS

For information about . . . Refer to . . . 

(1) Applications for permit to drill, 30 CFR 250, subpart D. 

(2) Development and Production Plans (DPP), 30 CFR 550, subpart B. 

(3) Downhole commingling, 30 CFR 250, subpart K. 


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§ 250.103 30 CFR Ch. II (7–1–13 Edition) 

TABLE—WHERE TO FIND INFORMATION FOR CONDUCTING OPERATIONS—Continued 

For information about . . . Refer to . . . 

(4) Exploration Plans (EP), 30 CFR, 550, subpart B. 

(5) Flaring, 30 CFR 250, subpart K. 

(6) Gas measurement, 30 CFR 250, subpart L. 

(7) Off-lease geological and geophysical permits, 30 CFR 551. 

(8) Oil spill financial responsibility coverage, 30 CFR 553. 

(9) Oil and gas production safety systems, 30 CFR 250, subpart H. 

(10) Oil spill response plans, 30 CFR 254. 

(11) Oil and gas well-completion operations, 30 CFR 250, subpart E. 

(12) Oil and gas well-workover operations, 30 CFR 250, subpart F. 

(13) Decommissioning Activities, 30 CFR 250, subpart Q. 

(14) Platforms and structures, 30 CFR 250, subpart I. 

(15) Pipelines and Pipeline Rights-of-Way, 30 CFR 250, subpart J and 30 CFR 550, subpart J. 

(16) Sulphur operations, 30 CFR 250, subpart P. 

(17) Training, 30 CFR 250, subpart O. 

(18) Unitization, 30 CFR 250, subpart M. 

§ 250.103 Where can I find more information about the requirements in 

this part? 

BSEE may issue Notices to Lessees 

and Operators (NTLs) that clarify, supplement, or provide more detail about 

certain requirements. NTLs may also 

outline what you must provide as required information in your various submissions to BSEE. 

§ 250.104 How may I appeal a decision 

made under BSEE regulations? 

To appeal orders or decisions issued 

under BSEE regulations in 30 CFR 

parts 250 to 282, follow the procedures 

in 30 CFR part 290. 

§ 250.105 Definitions. 

Terms used in this part will have the 

meanings given in the Act and as defined in this section: 

Act means the OCS Lands Act, as 

amended (43 U.S.C. 1331 et seq.). 

Affected State means with respect to 

any program, plan, lease sale, or other 

activity proposed, conducted, or approved under the provisions of the Act, 

any State: 

(1) The laws of which are declared, 

under section 4(a)(2) of the Act, to be 

the law of the United States for the 

portion of the OCS on which such activity is, or is proposed to be, conducted; 

(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installation or other device permanently 

or temporarily attached to the seabed; 

(3) Which is receiving, or according 

to the proposed activity, will receive 

oil for processing, refining, or transshipment that was extracted from the 

OCS and transported directly to such 

State by means of vessels or by a combination of means including vessels; 

(4) Which is designated by the Secretary as a State in which there is a 

substantial probability of significant 

impact on or damage to the coastal, 

marine, or human environment, or a 

State in which there will be significant 

changes in the social, governmental, or 

economic infrastructure, resulting 

from the exploration, development, and 

production of oil and gas anywhere on 

the OCS; or 

(5) In which the Secretary finds that 

because of such activity there is, or 

will be, a significant risk of serious 

damage, due to factors such as prevailing winds and currents to the marine or coastal environment in the 

event of any oil spill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities. 

Air pollutant means any airborne 

agent or combination of agents for 

which the Environmental Protection 

Agency (EPA) has established, under 

section 109 of the Clean Air Act, national primary or secondary ambient 

air quality standards. 

Analyzed geological information means 

data collected under a permit or a lease 

that have been analyzed. Analysis may 

include, but is not limited to, identification of lithologic and fossil content, core analysis, laboratory analyses 

of physical and chemical properties, 


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Safety & Environmental Enforcement, Interior § 250.105 

well logs or charts, results from formation fluid tests, and descriptions of hydrocarbon occurrences or hazardous 

conditions. 

Ancillary activities mean those activities on your lease or unit that you: 

(1) Conduct to obtain data and information to ensure proper exploration or 

development of your lease or unit; and 

(2) Can conduct without Bureau of 

Ocean Energy Management (BOEM) approval of an application or permit. 

Archaeological interest means capable 

of providing scientific or humanistic 

understanding of past human behavior, 

cultural adaptation, and related topics 

through the application of scientific or 

scholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation. 

Archaeological resource means any 

material remains of human life or activities that are at least 50 years of age 

and that are of archaeological interest. 

Attainment area means, for any air 

pollutant, an area that is shown by 

monitored data or that 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 and safest technology 

(BAST) means the best available and 

safest technologies that the BSEE Director determines to be economically 

feasible wherever failure of equipment 

would have a significant effect on safety, health, or the environment. 

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 Regional Supervisor will verify the BACT on a caseby-case basis, and it may include reductions achieved through the application of processes, systems, and techniques for the control of each air pollutant. 

Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that 

interactively determine the productivity, state, condition, and quality of 

the terrestrial ecosystem from the 

shoreline inward to the boundaries of 

the coastal zone. 

Coastal zone means the coastal waters 

(including the lands therein and thereunder) and the adjacent shorelands (including the waters therein and thereunder) strongly influenced by each 

other and in proximity to the 

shorelands of the several coastal 

States. The coastal zone includes islands, transition and intertidal areas, 

salt marshes, wetlands, and beaches. 

The coastal zone extends seaward to 

the outer limit of the U.S. territorial 

sea and extends inland from the shorelines to the extent necessary to control 

shorelands, the uses of which have a direct and significant impact on the 

coastal waters, and the inward boundaries of which may be identified by the 

several coastal States, under the authority in section 305(b)(1) of the Coastal Zone Management Act (CZMA) of 

1972. 

Competitive reservoir means a reservoir in which there are one or more 

producible or producing well completions on each of two or more leases or 

portions of leases, with different lease 

operating interests, from which the lessees plan future production. 

Correlative rights when used with respect to lessees of adjacent leases, 

means the right of each lessee to be afforded an equal opportunity to explore 

for, develop, and produce, without 

waste, minerals from a common source. 

Data means facts and statistics, 

measurements, or samples that have 

not been analyzed, processed, or interpreted. 

Departures mean approvals granted 

by the appropriate BSEE or BOEM representative for operating requirements/ 

procedures other than those specified 

in the regulations found in this part. 

These requirements/procedures may be 

necessary to control a well; properly 

develop a lease; conserve natural resources, or protect life, property, or 

the marine, coastal, or human environment. 

Development means those activities 

that take place following discovery of 

minerals in paying quantities, including but not limited to geophysical activity, drilling, platform construction, 

and operation of all directly related onshore support facilities, and which are 


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§ 250.105 30 CFR Ch. II (7–1–13 Edition) 

for the purpose of producing the minerals discovered. 

Development geological and geophysical 

(G&G) activities mean those G&G and 

related data-gathering activities on 

your lease or unit that you conduct following discovery of oil, gas, or sulphur 

in paying quantities to detect or imply 

the presence of oil, gas, or sulphur in 

commercial quantities. 

Director means the Director of BSEE 

of the U.S. Department of the Interior, 

or an official authorized to act on the 

Director’s behalf. 

District Manager means the BSEE officer with authority and responsibility 

for operations or other designated program functions for a district within a 

BSEE Region. 

Easement means an authorization for 

a nonpossessory, nonexclusive interest 

in a portion of the OCS, whether leased 

or unleased, which specifies the rights 

of the holder to use the area embraced 

in the easement in a manner consistent 

with the terms and conditions of the 

granting authority. 

Eastern Gulf of Mexico means all OCS 

areas of the Gulf of Mexico the BOEM 

Director decides are adjacent to the 

State of Florida. The Eastern Gulf of 

Mexico is not the same as the Eastern 

Planning Area, an area established for 

OCS lease sales. 

Emission offsets mean emission reductions obtained from facilities, either 

onshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan (EP) or Development and Production Plan (DPP). 

Enhanced recovery operations mean 

pressure maintenance operations, secondary and tertiary recovery, cycling, 

and similar recovery operations that 

alter the natural forces in a reservoir 

to increase the ultimate recovery of oil 

or gas. 

Existing facility, as used in 30 CFR 

550.303, means an OCS facility described in an Exploration Plan or a Development and Production Plan approved before June 2, 1980. 

Exploration means the commercial 

search for oil, gas, or sulphur. Activities classified as exploration include 

but are not limited to: 

(1) Geophysical and geological (G&G) 

surveys using magnetic, gravity, seismic reflection, seismic refraction, gas 

sniffers, coring, or other systems to detect or imply the presence of oil, gas, 

or sulphur; and 

(2) Any drilling conducted for the 

purpose of searching for commercial 

quantities of oil, gas, and sulphur, including the drilling of any additional 

well needed to delineate any reservoir 

to enable the lessee to decide whether 

to proceed with development and production. 

Facility means: 

(1) As used in §250.130, all installations permanently or temporarily attached to the seabed on the OCS (including manmade islands and bottomsitting structures). They include mobile offshore drilling units (MODUs) or 

other vessels engaged in drilling or 

downhole operations, used for oil, gas 

or sulphur drilling, production, or related activities. They include all floating production systems (FPSs), variously described as column-stabilizedunits (CSUs); floating production, storage and offloading facilities (FPSOs); 

tension-leg platforms (TLPs); spars, 

etc. They also include facilities for 

product measurement and royalty determination (e.g., lease Automatic Custody Transfer Units, gas meters) of 

OCS production on installations not on 

the OCS. Any group of OCS installations interconnected with walkways, or 

any group of installations that includes a central or primary installation with processing equipment and 

one or more satellite or secondary installations is a single facility. The Regional Supervisor may decide that the 

complexity of the individual installations justifies their classification as 

separate facilities. 

(2) As used in 30 CFR 550.303, means 

all installations or devices permanently or temporarily attached to the 

seabed. They include mobile offshore 

drilling units (MODUs), even while operating in the ‘‘tender assist’’ mode 

(i.e., with skid-off drilling units) or 

other vessels engaged in drilling or 

downhole operations. They are used for 

exploration, development, and production activities for oil, gas, or sulphur 

and emit or have the potential to emit 

any air pollutant from one or more 

sources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating 


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Safety & Environmental Enforcement, Interior § 250.105 

production, storage and offloading facilities (FPSOs); tension-leg platforms 

(TLPs); spars, etc. During production, 

multiple installations or devices are a 

single facility if the installations or 

devices are at a single site. Any vessel 

used to transfer production from an 

offshore facility is part of the facility 

while it is physically attached to the 

facility. 

(3) As used in §250.490(b), means a 

vessel, a structure, or an artificial island used for drilling, well completion, 

well-workover, or production operations. 

(4) As used in §§250.900 through 

250.921, means all installations or devices permanently or temporarily attached to the seabed. They are used for 

exploration, development, and production activities for oil, gas, or sulphur 

and emit or have the potential to emit 

any air pollutant from one or more 

sources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating 

production, storage and offloading facilities (FPSOs); tension-leg platforms 

(TLPs); spars, etc. During production, 

multiple installations or devices are a 

single facility if the installations or 

devices are at a single site. Any vessel 

used to transfer production from an 

offshore facility is part of the facility 

while it is physically attached to the 

facility. 

(5) As used in subpart S of this part, 

all types of structures permanently or 

temporarily attached to the seabed 

(e.g., mobile offshore drilling units 

(MODUs); floating production systems; 

floating production, storage and offloading facilities; tension-leg platforms; and spars) that are used for exploration, development, and production 

activities for oil, gas, or sulphur in the 

OCS. Facilities also include DOI-regulated pipelines. 

Flaring means the burning of natural 

gas as it is released into the atmosphere. 

Gas reservoir means a reservoir that 

contains hydrocarbons predominantly 

in a gaseous (single-phase) state. 

Gas-well completion means a well completed in a gas reservoir or in the associated gas-cap of an oil reservoir. 

Geological and geophysical (G&G) explorations mean those G&G surveys on 

your lease or unit that use seismic reflection, seismic refraction, magnetic, 

gravity, gas sniffers, coring, or other 

systems to detect or imply the presence of oil, gas, or sulphur in commercial quantities. 

Governor means the Governor of a 

State, or the person or entity designated by, or under, State law to exercise the powers granted to such Governor under the Act. 

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 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. 

Human environment means the physical, social, and economic components, 

conditions, and factors that interactively determine the state, condition, and quality of living conditions, 

employment, and health of those affected, directly or indirectly, by activities occurring on the OCS. 

Interpreted geological information 

means geological knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological significance of data and analyzed 

geological information. 

Interpreted geophysical information 

means geophysical knowledge, often in 

the form of schematic cross sections, 3- 

dimensional representations, and maps, 

developed by determining the geological significance of geophysical data 

and analyzed geophysical information. 

Lease means an agreement that is 

issued under section 8 or maintained 


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§ 250.105 30 CFR Ch. II (7–1–13 Edition) 

under section 6 of the Act and that authorizes exploration for, and development and production of, minerals. The 

term also means the area covered by 

that authorization, whichever the context requires. 

Lease term pipelines mean those pipelines owned and operated by a lessee or 

operator that are completely contained 

within the boundaries of a single lease, 

unit, or contiguous (not cornering) 

leases of that lessee or operator. 

Lessee means a person who has entered into a lease with the United 

States to explore for, develop, and 

produce the leased minerals. The term 

lessee also includes the BOEM-approved assignee of the lease, and the 

owner or the BOEM-approved assignee 

of operating rights for the lease. 

Major Federal action means any action or proposal by the Secretary that 

is subject to the provisions of section 

102(2)(C) of the National Environmental 

Policy Act of 1969, 42 U.S.C. (2)(C) (i.e., 

an action that will have a significant 

impact on the quality of the human environment requiring preparation of an 

environmental impact statement under 

section 102(2)(C) of the National Environmental Policy Act). 

Marine environment means the physical, atmospheric, and biological components, conditions, and factors that 

interactively determine the productivity, state, condition, and quality of 

the marine ecosystem. These include 

the waters of the high seas, the contiguous zone, transitional and intertidal 

areas, salt marshes, and wetlands within the coastal zone and on the OCS. 

Material remains mean physical evidence of human habitation, occupation, 

use, or activity, including the site, location, or context in which such evidence is situated. 

Maximum efficient rate (MER) means 

the maximum sustainable daily oil or 

gas withdrawal rate from a reservoir 

that will permit economic development 

and depletion of that reservoir without 

detriment to ultimate recovery. 

Maximum production rate (MPR) 

means the approved maximum daily 

rate at which oil or gas may be produced from a specified oil-well or gaswell completion. 

Minerals include oil, gas, sulphur, 

geopressured-geothermal and associated resources, and all other minerals 

that are authorized by an Act of Congress to be produced. 

Natural resources include, without 

limiting the generality thereof, oil, 

gas, and all other minerals, and fish, 

shrimp, oysters, clams, crabs, lobsters, 

sponges, kelp, and other marine animal 

and plant life but does not include 

water power or the use of water for the 

production of power. 

Nonattainment area means, for any air 

pollutant, an area that is shown by 

monitored data or that 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. 

Nonsensitive reservoir means a reservoir in which ultimate recovery is 

not decreased by high reservoir production rates. 

Oil reservoir means a reservoir that 

contains hydrocarbons predominantly 

in a liquid (single-phase) state. 

Oil reservoir with an associated gas cap 

means a reservoir that contains hydrocarbons in both a liquid and gaseous 

(two-phase) state. 

Oil-well completion means a well completed in an oil reservoir or in the oil 

accumulation of an oil reservoir with 

an associated gas cap. 

Operating rights mean any interest 

held in a lease with the right to explore 

for, develop, and produce leased substances. 

Operator means the person the lessee(s) designates as having control or 

management of operations on the 

leased area or a portion thereof. An operator may be a lessee, the BSEE-approved or BOEM-approved designated 

agent of the lessee(s), or the holder of 

operating rights under a BOEM-approved operating rights assignment. 

Outer Continental Shelf (OCS) means 

all submerged lands lying seaward and 

outside of the area of lands beneath 

navigable waters as defined in section 2 

of the Submerged Lands Act (43 U.S.C. 

1301) whose subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. 

Person includes a natural person, an 

association (including partnerships, 

joint ventures, and trusts), a State, a 

political subdivision of a State, or a 


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Safety & Environmental Enforcement, Interior § 250.105 

private, public, or municipal corporation. 

Pipelines are the piping, risers, and 

appurtenances installed for transporting oil, gas, sulphur, and produced 

waters. 

Processed geological or geophysical information means data collected under a 

permit or a lease that have been processed or reprocessed. Processing involves changing the form of data to facilitate interpretation. Processing operations may include, but are not limited to, applying corrections for known 

perturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is 

the additional processing other than 

ordinary processing used in the general 

course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study 

of a specific problem area. 

Production means those activities 

that take place after the successful 

completion of any means for the removal of minerals, including such removal, field operations, transfer of 

minerals to shore, operation monitoring, maintenance, and workover operations. 

Production areas are those areas 

where flammable petroleum gas, volatile liquids or sulphur are produced, 

processed (e.g., compressed), stored, 

transferred (e.g., pumped), or otherwise 

handled before entering the transportation process. 

Projected emissions mean emissions, 

either controlled or uncontrolled, from 

a source or sources. 

Prospect means a geologic feature 

having the potential for mineral deposits. 

Regional Director means the BSEE officer with responsibility and authority 

for a Region within BSEE. 

Regional Supervisor means the BSEE 

officer with responsibility and authority for operations or other designated 

program functions within a BSEE Region. 

Right-of-use means any authorization 

issued under 30 CFR Part 550 to use 

OCS lands. 

Right-of-way pipelines are those pipelines that are contained within: 

(1) The boundaries of a single lease or 

unit, but are not owned and operated 

by a lessee or operator of that lease or 

unit; 

(2) The boundaries of contiguous (not 

cornering) leases that do not have a 

common lessee or operator; 

(3) The boundaries of contiguous (not 

cornering) leases that have a common 

lessee or operator but are not owned 

and operated by that common lessee or 

operator; or 

(4) An unleased block(s). 

Routine operations, for the purposes of 

subpart F, mean any of the following 

operations conducted on a well with 

the tree installed: 

(1) Cutting paraffin; 

(2) Removing and setting pumpthrough-type tubing plugs, gas-lift 

valves, and subsurface safety valves 

that can be removed by wireline operations; 

(3) Bailing sand; 

(4) Pressure surveys; 

(5) Swabbing; 

(6) Scale or corrosion treatment; 

(7) Caliper and gauge surveys; 

(8) Corrosion inhibitor treatment; 

(9) Removing or replacing subsurface 

pumps; 

(10) Through-tubing logging 

(diagnostics); 

(11) Wireline fishing; 

(12) Setting and retrieving other subsurface flow-control devices; and 

(13) Acid treatments. 

Sensitive reservoir means a reservoir 

in which the production rate will affect 

ultimate recovery. 

Significant archaeological resource 

means those archaeological resources 

that meet the criteria of significance 

for eligibility to the National Register 

of Historic Places as defined in 36 CFR 

60.4, or its successor. 

Suspension means a granted or directed deferral of the requirement to 

produce (Suspension of Production 

(SOP)) or to conduct leaseholding operations (Suspension of Operations 

(SOO)). 

Venting means the release of gas into 

the atmosphere without igniting it. 

This includes gas that is released underwater and bubbles to the atmosphere. 

Waste of oil, gas, or sulphur means: 

(1) The physical waste of oil, gas, or 

sulphur; 


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§ 250.106 30 CFR Ch. II (7–1–13 Edition) 

(2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy; 

(3) The locating, spacing, drilling, 

equipping, operating, or producing of 

any oil, gas, or sulphur well(s) in a 

manner that causes or tends to cause a 

reduction in the quantity of oil, gas, or 

sulphur ultimately recoverable under 

prudent and proper operations or that 

causes or tends to cause unnecessary or 

excessive surface loss or destruction of 

oil or gas; or 

(4) The inefficient storage of oil. 

Welding means all activities connected with welding, including hot tapping and burning. 

Wellbay is the area on a facility within the perimeter of the outermost 

wellheads. 

Well-completion operations mean the 

work conducted to establish production 

from a well after the production-casing 

string has been set, cemented, and 

pressure-tested. 

Well-control fluid means drilling mud, 

completion fluid, or workover fluid as 

appropriate to the particular operation 

being conducted. 

Western Gulf of Mexico means all OCS 

areas of the Gulf of Mexico except 

those the BOEM Director decides are 

adjacent to the State of Florida. The 

Western Gulf of Mexico is not the same 

as the Western Planning Area, an area 

established for OCS lease sales. 

Workover operations mean the work 

conducted on wells after the initial 

well-completion operation for the purpose of maintaining or restoring the 

productivity of a well. 

You means a lessee, the owner or 

holder of operating rights, a designated 

operator or agent of the lessee(s), a 

pipeline right-of-way holder, or a State 

lessee granted a right-of-use and easement. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20439, Apr. 5, 2013] 

PERFORMANCE STANDARDS

§ 250.106 What standards will the Director use to regulate lease operations? 

The Director will regulate all operations under a lease, right-of-use and 

easement, or right-of-way to: 

(a) Promote orderly exploration, development, and production of mineral 

resources; 

(b) Prevent injury or loss of life; 

(c) Prevent damage to or waste of 

any natural resource, property, or the 

environment; and 

(d) Cooperate and consult with affected States, local governments, other 

interested parties, and relevant Federal agencies. 

§ 250.107 What must I do to protect 

health, safety, property, and the environment? 

(a) You must protect health, safety, 

property, and the environment by: 

(1) Performing all operations in a 

safe and workmanlike manner; and 

(2) Maintaining all equipment and 

work areas in a safe condition. 

(b) You must immediately control, 

remove, or otherwise correct any hazardous oil and gas accumulation or 

other health, safety, or fire hazard. 

(c) You must use the best available 

and safest technology (BAST) whenever practical on all exploration, development, and production operations. In 

general, we consider your compliance 

with BSEE regulations to be the use of 

BAST. 

(d) The Director may require additional measures to ensure the use of 

BAST: 

(1) To avoid the failure of equipment 

that would have a significant effect on 

safety, health, or the environment; 

(2) If it is economically feasible; and 

(3) If the benefits outweigh the costs. 

§ 250.108 What requirements must I 

follow for cranes and other material-handling equipment? 

(a) All cranes installed on fixed platforms must be operated in accordance 

with American Petroleum Institute’s 

Recommended Practice for Operation 

and Maintenance of Offshore Cranes, 

API RP 2D (as incorporated by reference in §250.198). 

(b) All cranes installed on fixed platforms must be equipped with a functional anti-two block device. 

(c) If a fixed platform is installed 

after March 17, 2003, all cranes on the 

platform must meet the requirements 

of American Petroleum Institute Specification for Offshore Pedestal Mounted 


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Safety & Environmental Enforcement, Interior § 250.113 

Cranes, API Spec 2C (as incorporated 

by reference in §250.198). 

(d) All cranes manufactured after 

March 17, 2003, and installed on a fixed 

platform, must meet the requirements 

of API Spec 2C. 

(e) You must maintain records specific to a crane or the operation of a 

crane installed on an OCS fixed platform, as follows: 

(1) Retain all design and construction 

records, including installation records 

for any anti-two block safety devices, 

for the life of the crane. The records 

must be kept at the OCS fixed platform. 

(2) Retain all inspection, testing, and 

maintenance records of cranes for at 

least 4 years. The records must be kept 

at the OCS fixed platform. 

(3) Retain the qualification records of 

the crane operator and all rigger personnel for at least 4 years. The records 

must be kept at the OCS fixed platform. 

(f) You must operate and maintain 

all other material-handling equipment 

in a manner that ensures safe operations and prevents pollution. 

§ 250.109 What documents must I prepare and maintain related to welding? 

(a) You must submit a Welding Plan 

to the District Manager before you 

begin drilling or production activities 

on a lease. You may not begin welding 

until the District Manager has approved your plan. 

(b) You must keep the following at 

the site where welding occurs: 

(1) A copy of the plan and its approval letter; and 

(2) Drawings showing the designated 

safe-welding areas. 

§ 250.110 What must I include in my 

welding plan? 

You must include all of the following 

in the welding plan that you prepare 

under §250.109: 

(a) Standards or requirements for 

welders; 

(b) How you will ensure that only 

qualified personnel weld; 

(c) Practices and procedures for safe 

welding that address: 

(1) Welding in designated safe areas; 

(2) Welding in undesignated areas, including wellbay; 

(3) Fire watches; 

(4) Maintenance of welding equipment; and 

(5) Plans showing all designated safewelding areas. 

(d) How you will prevent spark-producing activities (i.e., grinding, abrasive blasting/cutting and arc-welding) 

in hazardous locations. 

§ 250.111 Who oversees operations 

under my welding plan? 

A welding supervisor or a designated 

person in charge must be thoroughly 

familiar with your welding plan. This 

person must ensure that each welder is 

properly qualified according to the 

welding plan. This person also must inspect all welding equipment before 

welding. 

§ 250.112 What standards must my 

welding equipment meet? 

Your welding equipment must meet 

the following requirements: 

(a) All engine-driven welding equipment must be equipped with spark arrestors and drip pans; 

(b) Welding leads must be completely 

insulated and in good condition; 

(c) Hoses must be leak-free and 

equipped with proper fittings, gauges, 

and regulators; and 

(d) Oxygen and fuel gas bottles must 

be secured in a safe place. 

§ 250.113 What procedures must I follow when welding? 

(a) Before you weld, you must move 

any equipment containing hydrocarbons or other flammable substances 

at least 35 feet horizontally from the 

welding area. You must move similar 

equipment on lower decks at least 35 

feet from the point of impact where 

slag, sparks, or other burning materials could fall. If moving this equipment is impractical, you must protect 

that equipment with flame-proofed 

covers, shield it with metal or fire-resistant guards or curtains, or render 

the flammable substances inert. 

(b) While you weld, you must monitor all water-discharge-point sources 

from hydrocarbon-handling vessels. If a 

discharge of flammable fluids occurs, 

you must stop welding. 


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§ 250.114 30 CFR Ch. II (7–1–13 Edition) 

(c) If you cannot weld in one of the 

designated safe-welding areas that you 

listed in your safe welding plan, you 

must meet the following requirements: 

(1) You may not begin welding until: 

(i) The welding supervisor or designated person in charge advises in 

writing that it is safe to weld. 

(ii) You and the designated person in 

charge inspect the work area and areas 

below it for potential fire and explosion 

hazards. 

(2) During welding, the person in 

charge must designate one or more persons as a fire watch. The fire watch 

must: 

(i) Have no other duties while actual 

welding is in progress; 

(ii) Have usable firefighting equipment; 

(iii) Remain on duty for 30 minutes 

after welding activities end; and 

(iv) Maintain a continuous surveillance with a portable gas detector during the welding and burning operation 

if welding occurs in an area not 

equipped with a gas detector. 

(3) You may not weld piping, containers, tanks, or other vessels that 

have contained a flammable substance 

unless you have rendered the contents 

inert and the designated person in 

charge has determined it is safe to 

weld. This does not apply to approved 

hot taps. 

(4) You may not weld within 10 feet 

of a wellbay unless you have shut in all 

producing wells in that wellbay. 

(5) You may not weld within 10 feet 

of a production area, unless you have 

shut in that production area. 

(6) You may not weld while you drill, 

complete, workover, or conduct 

wireline operations unless: 

(i) The fluids in the well (being 

drilled, completed, worked over, or 

having wireline operations conducted) 

are noncombustible; and 

(ii) You have precluded the entry of 

formation hydrocarbons into the 

wellbore by either mechanical means 

or a positive overbalance toward the 

formation. 

§ 250.114 How must I install and operate electrical equipment? 

The requirements in this section 

apply to all electrical equipment on all 

platforms, artificial islands, fixed 

structures, and their facilities. 

(a) You must classify all 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, or API RP 

505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities 

Classified as Class I, Zone 0, Zone 1, 

and Zone 2 (as incorporated by reference in §250.198). 

(b) Employees who maintain your 

electrical systems must have expertise 

in area classification and the performance, operation and hazards of electrical equipment. 

(c) You must install all electrical 

systems according to API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for 

Fixed and Floating Offshore Petroleum 

Facilities for Unclassified and Class I, 

Division 1, and Division 2 Locations (as 

incorporated by reference in §250.198), 

or API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating 

Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, 

and Zone 2 Locations (as incorporated 

by reference in §250.198). 

(d) On each engine that has an electric ignition system, you must use an 

ignition system designed and maintained to reduce the release of electrical energy. 

§§ 250.115–250.117 [Reserved] 

§ 250.118 Will BSEE approve gas injection? 

The Regional Supervisor may authorize you to inject gas on the OCS, on 

and off-lease, to promote conservation 

of natural resources and to prevent 

waste. 

(a) To receive BSEE approval for injection, you must: 

(1) Show that the injection will not 

result in undue interference with operations under existing leases; and 

(2) Submit a written application to 

the Regional Supervisor for injection 

of gas. 

(b) The Regional Supervisor will approve gas injection applications that: 


ehiers on DSK2VPTVN1PROD with CFR
61 

Safety & Environmental Enforcement, Interior § 250.125 

(1) Enhance recovery; 

(2) Prevent flaring of casinghead gas; 

or 

(3) Implement other conservation 

measures approved by the Regional Supervisor. 

§ 250.119 [Reserved] 

§ 250.120 How does injecting, storing, 

or treating gas affect my royalty 

payments? 

(a) If you produce gas from an OCS 

lease and inject it into a reservoir on 

the lease or unit for the purposes cited 

in §250.118(b), you are not required to 

pay royalties until you remove or sell 

the gas from the reservoir. 

(b) If you produce gas from an OCS 

lease and store it according to 30 CFR 

550.119, you must pay royalty before injecting it into the storage reservoir. 

(c) If you produce gas from an OCS 

lease and treat it at an off-lease or offunit location, you must pay royalties 

when the gas is first produced. 

§ 250.121 What happens when the reservoir contains both original gas in 

place and injected gas? 

If the reservoir contains both original gas in place and injected gas, when 

you produce gas from the reservoir you 

must use a BSEE-approved formula to 

determine the amounts of injected or 

stored gas and gas original to the reservoir. 

§ 250.122 What effect does subsurface 

storage have on the lease term? 

If you use a lease area for subsurface 

storage of gas, it does not affect the 

continuance or expiration of the lease. 

§ 250.123 [Reserved] 

§ 250.124 Will BSEE approve gas injection into the cap rock containing a 

sulphur deposit? 

To receive the Regional Supervisor’s 

approval to inject gas into the cap rock 

of a salt dome containing a sulphur deposit, you must show that the injection: 

(a) Is necessary to recover oil and gas 

contained in the cap rock; and 

(b) Will not significantly increase potential hazards to present or future 

sulphur mining operations. 

FEES

§ 250.125 Service fees. 

(a) The table in this paragraph (a) 

shows the fees that you must pay to 

BSEE for the services listed. The fees 

will be adjusted periodically according 

to the Implicit Price Deflator for Gross 

Domestic Product by publication of a 

document in the FEDERAL REGISTER. If 

a significant adjustment is needed to 

arrive at the new actual cost for any 

reason other than inflation, then a proposed rule containing the new fees will 

be published in the FEDERAL REGISTER

for comment. 

Service—processing of the following: Fee amount 30 CFR citation 

(1) [Reserved] 

(2) [Reserved] 

(3) Suspension of Operations/Suspension of Production 

(SOO/SOP) Request. 

$1,968 ..................................... § 250.171(e). 

(4) [Reserved] 

(5) [Reserved] 

(6) Deepwater Operations Plan ................................................. $3,336 ..................................... § 250.292(p). 

(7) [Reserved] 

(8) Application for Permit to Drill (APD; Form BSEE–0123) ..... $1,959 for initial applications 

only; no fee for revisions.

§ 250.410(d); § 250.513(b); 

§ 250.1617(a). 

(9) Application for Permit to Modify (APM; Form BSEE–0124) $116 ........................................ § 250.465(b); § 250.513(b); 

§ 250.613(b); § 250.1618(a); 

§ 250.1704(g). 


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§ 250.125 30 CFR Ch. II (7–1–13 Edition) 

Service—processing of the following: Fee amount 30 CFR citation 

(10) New Facility Production Safety System Application for facility with more than 125 components.$5,030 A component is a 

piece of equipment or ancillary system that is protected 

by one or more of the safety 

devices required by API RP 

14C (as incorporated by reference in § 250.198); 

$13,238 additional fee will 

be charged if BSEE deems 

it necessary to visit a facility 

offshore, and $6,884 to visit 

a facility in a shipyard.

§ 250.802(e). 

(11) New Facility Production Safety System Application for facility with 25–125 components.$1,218 Additional fee of 

$8,313 will be charged if 

BSEE deems it necessary to 

visit a facility offshore, and 

$4,766 to visit a facility in a 

shipyard.

§ 250.802(e). 

(12) New Facility Production Safety System Application for facility with fewer than 25 components.$604 ........................................ § 250.802(e). 

(13) Production Safety System Application—Modification with 

more than 125 components reviewed.

$561 ........................................ § 250.802(e). 

(14) Production Safety System Application—Modification with 

25–125 components reviewed.

$201 ........................................ § 250.802(e). 

(15) Production Safety System Application—Modification with 

fewer than 25 components reviewed.

$85 .......................................... § 250.802(e). 

(16) Platform Application—Installation—Under the Platform 

Verification Program.

$21,075 ................................... § 250.905(l). 

(17) Platform Application—Installation—Fixed Structure Under 

the Platform Approval Program.

$3,018 ..................................... § 250.905(l). 

(18) Platform Application—Installation—Caisson/Well Protector.$1,536 ..................................... § 250.905(l) 

(19) Platform Application—Modification/Repair ......................... $3,601 ..................................... § 250.905(l). 

(20) New Pipeline Application (Lease Term) ............................ $3,283 ..................................... § 250.1000(b). 

(21) Pipeline Application—Modification (Lease Term) .............. $1,906 ..................................... § 250.1000(b). 

(22) Pipeline Application—Modification (ROW) ......................... $3,865 ..................................... § 250.1000(b). 

(23) Pipeline Repair Notification ................................................ $360 ........................................ § 250.1008(e). 

(24) Pipeline Right-of-Way (ROW) Grant Application ............... $2,569 ..................................... § 250.1015(a). 

(25) Pipeline Conversion of Lease Term to ROW .................... $219 ........................................ § 250.1015(a). 

(26) Pipeline ROW Assignment ................................................. $186 ........................................ § 250.1018(b). 

(27) 500 Feet From Lease/Unit Line Production Request ........ $3,608 ..................................... § 250.1156(a). 

(28) Gas Cap Production Request ............................................ $4,592 ..................................... § 250.1157. 

(29) Downhole Commingling Request ....................................... $5,357 ..................................... § 250.1158(a). 

(30) Complex Surface Commingling and Measurement Application.$3,760 ..................................... § 250.1202(a); § 250.1203(b); 

§ 250.1204(a). 

(31) Simple Surface Commingling and Measurement Application.$1,271 ..................................... § 250.1202(a); § 250.1203(b); 

§ 250.1204(a). 

(32) Voluntary Unitization Proposal or Unit Expansion ............. $11,698 ................................... § 250.1303(d). 

(33) Unitization Revision ............................................................ $831 ........................................ § 250.1303(d). 

(34) Application to Remove a Platform or Other Facility .......... $4,342 ..................................... § 250.1727. 

(35) Application to Decommission a Pipeline (Lease Term) ..... $1,059 ..................................... § 250.1751(a) or 

§ 250.1752(a). 

(36) Application to Decommission a Pipeline (ROW) ............... $2,012 ..................................... § 250.1751(a) or 

§ 250.1752(a). 

(b) Payment of the fees listed in 

paragraph (a) of this section must accompany the submission of the document for approval or be sent to an office identified by the Regional Director. Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application 

is returned to you as incomplete, you 

are not required to submit a new fee 

when you submit the amended application. 

(c) Verbal approvals are occasionally 

given in special circumstances. Any action that will be considered a verbal 

permit approval requires either a paper 

permit application to follow the verbal 

approval or an electronic application 

submittal within 72 hours. Payment 

must be made with the completed 

paper or electronic application. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50891, Aug. 22, 2012] 


ehiers on DSK2VPTVN1PROD with CFR
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Safety & Environmental Enforcement, Interior § 250.136 

§ 250.126 Electronic payment instructions. 

You must file all payments electronically through Pay.gov. This includes, 

but is not limited to, all OCS applications or filing fee payments. The 

Pay.gov Web site may be accessed 

through a link on the BSEE Offshore 

Web site at: http://www.bsee.gov/offshore/ 

homepage or directly through Pay.gov 

at: https://www.pay.gov/paygov/. 

(a) If you submitted an application 

through eWell, you must use the interactive payment feature in that system, 

which directs you through Pay.gov. 

(b) For applications not submitted 

electronically through eWell, you must 

use credit card or automated clearing 

house (ACH) payments through the 

Pay.gov Web site, and you must include 

a copy of the Pay.gov confirmation receipt page with your application. 

INSPECTIONS OF OPERATIONS

§ 250.130 Why does BSEE conduct inspections? 

BSEE will inspect OCS facilities and 

any vessels engaged in drilling or other 

downhole operations. These include facilities under jurisdiction of other Federal agencies that we inspect by agreement. We conduct these inspections: 

(a) To verify that you are conducting 

operations according to the Act, the 

regulations, the lease, right-of-way, 

the BOEM-approved Exploration Plan 

or Development and Production Plans; 

or right-of-use and easement, and other 

applicable laws and regulations; and 

(b) To determine whether equipment 

designed to prevent or ameliorate 

blowouts, fires, spillages, or other 

major accidents has been installed and 

is operating properly according to the 

requirements of this part. 

§ 250.131 Will BSEE notify me before 

conducting an inspection? 

BSEE conducts both scheduled and 

unscheduled inspections. 

§ 250.132 What must I do when BSEE 

conducts an inspection? 

(a) When BSEE conducts an inspection, you must provide: 

(1) Access to all platforms, artificial 

islands, and other installations on your 

leases or associated with your lease, 

right-of-use and easement, or right-ofway; and 

(2) Helicopter landing sites and refueling facilities for any helicopters we 

use to regulate offshore operations. 

(b) You must make the following 

available for us to inspect: 

(1) The area covered under a lease, 

right-of-use and easement, right-ofway, or permit; 

(2) All improvements, structures, and 

fixtures on these areas; and 

(3) All records of design, construction, operation, maintenance, repairs, 

or investigations on or related to the 

area. 

§ 250.133 Will BSEE reimburse me for 

my expenses related to inspections? 

Upon request, BSEE will reimburse 

you for food, quarters, and transportation that you provide for BSEE representatives while they inspect lease 

facilities and operations. You must 

send us your reimbursement request 

within 90 days of the inspection. 

DISQUALIFICATION

§ 250.135 What will BSEE do if my operating performance is unacceptable? 

BSEE will determine if your operating performance is unacceptable. 

BSEE will refer a determination of unacceptable performance to BOEM, who 

may disapprove or revoke your designation as operator on a single facility or multiple facilities. We will give 

you adequate notice and opportunity 

for a review by BSEE officials before 

making a determination that your operating performance is unacceptable. 

§ 250.136 How will BSEE determine if 

my operating performance is unacceptable? 

In determining if your operating performance is unacceptable, BSEE will 

consider, individually or collectively: 

(a) Accidents and their nature; 

(b) Pollution events, environmental 

damages and their nature; 

(c) Incidents of noncompliance; 

(d) Civil penalties; 

(e) Failure to adhere to OCS lease obligations; or 

(f) Any other relevant factors. 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.140 30 CFR Ch. II (7–1–13 Edition) 

SPECIAL TYPES OF APPROVALS

§ 250.140 When will I receive an oral 

approval? 

When you apply for BSEE approval of 

any activity, we normally give you a 

written decision. The following table 

shows circumstances under which we 

may give an oral approval. 

When you . . . We may . . . And . . . 

(a) Request approval orally Give you an oral approval, You must then confirm the oral request by sending us a written request within 72 hours. 

(b) Request approval in writing, Give you an oral approval if 

quick action is needed, 

We will send you a written approval afterward. It will include 

any conditions that we place on the oral approval. 

(c) Request approval orally for 

gas flaring, 

Give you an oral approval, You don’t have to follow up with a written request unless the 

Regional Supervisor requires it. When you stop the approved flaring, you must promptly send a letter summarizing the location, dates and hours, and volumes of liquid 

hydrocarbons produced and gas flared by the approved 

flaring (see 30 CFR 250, subpart K). 

§ 250.141 May I ever use alternate procedures or equipment? 

You may use alternate procedures or 

equipment after receiving approval as 

described in this section. 

(a) Any alternate procedures or 

equipment that you propose to use 

must provide a level of safety and environmental protection that equals or 

surpasses current BSEE requirements. 

(b) You must receive the District 

Manager’s or Regional Supervisor’s 

written approval before you can use alternate procedures or equipment. 

(c) To receive approval, you must either submit information or give an oral 

presentation to the appropriate Regional Supervisor. Your presentation 

must describe the site-specific application(s), performance characteristics, 

and safety features of the proposed procedure or equipment. 

§ 250.142 How do I receive approval 

for departures? 

We may approve departures to the 

operating requirements. You may 

apply for a departure by writing to the 

District Manager or Regional Supervisor. 

§§ 250.143–250.144 [Reserved] 

§ 250.145 How do I designate an agent 

or a local agent? 

(a) You or your designated operator 

may designate for the Regional Supervisor’s approval, or the Regional Director may require you to designate an 

agent empowered to fulfill your obligations under the Act, the lease, or the 

regulations in this part. 

(b) You or your designated operator 

may designate for the Regional Supervisor’s approval a local agent empowered to receive notices and submit requests, applications, notices, or supplemental information. 

§ 250.146 Who is responsible for fulfilling leasehold obligations? 

(a) When you are not the sole lessee, 

you and your co-lessee(s) are jointly 

and severally responsible for fulfilling 

your obligations under the provisions 

of 30 CFR parts 250 through 282 and 30 

CFR parts 550 through 582 unless otherwise provided in these regulations. 

(b) If your designated operator fails 

to fulfill any of your obligations under 

30 CFR parts 250 through 282 and 30 

CFR parts 550 through 582, the Regional Supervisor may require you or 

any or all of your co-lessees to fulfill 

those obligations or other operational 

obligations under the Act, the lease, or 

the regulations. 

(c) Whenever the regulations in 30 

CFR parts 250 through 282 and 30 CFR 

parts 550 through 582 require the lessee 

to meet a requirement or perform an 

action, the lessee, operator (if one has 

been designated), and the person actually performing the activity to which 

the requirement applies are jointly and 

severally responsible for complying 

with the regulation. 


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Safety & Environmental Enforcement, Interior § 250.154 

NAMING AND IDENTIFYING FACILITIES

AND WELLS (DOES NOT INCLUDE MODUS) 

§ 250.150 How do I name facilities and 

wells in the Gulf of Mexico Region? 

(a) Assign each facility a letter designation except for those types of facilities identified in paragraph (c)(1) of 

this section. For example, A, B, CA, or 

CB. 

(1) After a facility is installed, rename each predrilled well that was assigned only a number and was suspended temporarily at the mudline or 

at the surface. Use a letter and number 

designation. The letter used must be 

the same as that of the production facility, and the number used must correspond to the order in which the well 

was completed, not necessarily the 

number assigned when it was drilled. 

For example, the first well completed 

for production on Facility A would be 

renamed Well A–1, the second would be 

Well A–2, and so on; and 

(2) When you have more than one facility on a block, each facility installed, and not bridge-connected to 

another facility, must be named using 

a different letter in sequential order. 

For example, EC 222A, EC 222B, EC 

222C. 

(3) When you have more than one facility on multiple blocks in a local 

area being co-developed, each facility 

installed and not connected with a 

walkway to another facility should be 

named using a different letter in sequential order with the block number 

corresponding to the block on which 

the platform is located. For example, 

EC 221A, EC 222B, and EC 223C. 

(b) In naming multiple well caissons, 

you must assign a letter designation. 

(c) In naming single well caissons, 

you must use certain criteria as follows: 

(1) For single well caissons not attached to a facility with a walkway, 

use the well designation. For example, 

Well No. 1; 

(2) For single well caissons attached 

to a facility with a walkway, use the 

same designation as the facility. For 

example, rename Well No.10 as A–10; 

and 

(3) For single well caissons with production equipment, use a letter designation for the facility name and a 

letter plus number designation for the 

well. For example, the Well No. 1 caisson would be designated as Facility A, 

and the well would be Well A–1. 

§ 250.151 How do I name facilities in 

the Pacific Region? 

The operator assigns a name to the 

facility. 

§ 250.152 How do I name facilities in 

the Alaska Region? 

Facilities will be named and identified according to the Regional Director’s directions. 

§ 250.153 Do I have to rename an existing facility or well? 

You do not have to rename facilities 

installed and wells drilled before January 27, 2000, unless the Regional Director requires it. 

§ 250.154 What identification signs 

must I display? 

(a) You must identify all facilities, 

artificial islands, and mobile offshore 

drilling units with a sign maintained in 

a legible condition. 

(1) You must display an identification sign that can be viewed from the 

waterline on at least one side of the 

platform. The sign must use at least 3- 

inch letters and figures. 

(2) When helicopter landing facilities 

are present, you must display an additional identification sign that is visible 

from the air. The sign must use at 

least 12-inch letters and figures and 

must also display the weight capacity 

of the helipad unless noted on the top 

of the helipad. If this sign is visible to 

both helicopter and boat traffic, then 

the sign in paragraph (a)(1) of this section is not required. 

(3) Your identification sign must: 

(i) List the name of the lessee or designated operator; 

(ii) In the GOM OCS Region, list the 

area designation or abbreviation and 

the block number of the facility location as depicted on OCS Official Protraction Diagrams or leasing maps; 

(iii) In the Pacific OCS Region, list 

the lease number on which the facility 

is located; and 

(iv) List the name of the platform, 

structure, artificial island, or mobile 

offshore drilling unit. 


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§§ 250.160–250.167 30 CFR Ch. II (7–1–13 Edition) 

(b) You must identify singly completed wells and multiple completions 

as follows: 

(1) For each singly completed well, 

list the lease number and well number 

on the wellhead or on a sign affixed to 

the wellhead; 

(2) For wells with multiple completions, downhole splitter wells, and multilateral wells, identify each completion in addition to the well name and 

lease number individually on the well 

flowline at the wellhead; and 

(3) For subsea wells that flow individually into separate pipelines, affix the 

required sign on the pipeline or surface 

flowline dedicated to that subsea well 

at a convenient location on the receiving platform. For multiple subsea wells 

that flow into a common pipeline or 

pipelines, no sign is required. 

§§ 250.160–250.167 [Reserved] 

SUSPENSIONS

§ 250.168 May operations or production be suspended? 

(a) You may request approval of a 

suspension, or the Regional Supervisor 

may direct a suspension (Directed Suspension), for all or any part of a lease 

or unit area. 

(b) Depending on the nature of the 

suspended activity, suspensions are labeled either Suspensions of Operations 

(SOO) or Suspensions of Production 

(SOP). 

§ 250.169 What effect does suspension 

have on my lease? 

(a) A suspension may extend the 

term of a lease (see §250.180(b), (d), and 

(e)). The extension is equal to the 

length of time the suspension is in effect, except as provided in paragraph 

(b) of this section. 

(b) A Directed Suspension does not 

extend the term of a lease when the Regional Supervisor directs a suspension 

because of: 

(1) Gross negligence; or 

(2) A willful violation of a provision 

of the lease or governing statutes and 

regulations. 

§ 250.170 How long does a suspension 

last? 

(a) BSEE may issue suspensions for 

up to 5 years per suspension. The Regional Supervisor will set the length of 

the suspension based on the conditions 

of the individual case involved. BSEE 

may grant consecutive suspension periods. 

(b) An SOO ends automatically when 

the suspended operation commences. 

(c) An SOP ends automatically when 

production begins. 

(d) A Directed Suspension normally 

ends as specified in the letter directing 

the suspension. 

(e) BSEE may terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist or 

that other lease conditions warrant 

termination. The Regional Supervisor 

will notify you of the reasons for termination and the effective date. 

§ 250.171 How do I request a suspension? 

You must submit your request for a 

suspension to the Regional Supervisor, 

and BSEE must receive the request before the end of the lease term (i.e., end 

of primary term, end of the 180-day period following the last leaseholding operation, and end of a current suspension). Your request must include: 

(a) The justification for the suspension including the length of suspension 

requested; 

(b) A reasonable schedule of work 

leading to the commencement or restoration of the suspended activity; 

(c) A statement that a well has been 

drilled on the lease and determined to 

be producible according to §250.1603 

(SOP only), 30 CFR 550.115, or 30 CFR 

550.116; 

(d) A commitment to production 

(SOP only); and 

(e) The service fee listed in §250.125 of 

this subpart. 

§ 250.172 When may the Regional Supervisor grant or direct an SOO or 

SOP? 

The Regional Supervisor may grant 

or direct an SOO or SOP under any of 

the following circumstances: 

(a) When necessary to comply with 

judicial decrees prohibiting any activities or the permitting of those activities. The effective date of the suspension will be the effective date required 

by the action of the court; 


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67 

Safety & Environmental Enforcement, Interior § 250.175 

(b) When activities pose a threat of 

serious, irreparable, or immediate 

harm or damage. This would include a 

threat to life (including fish and other 

aquatic life), property, any mineral deposit, or the marine, coastal, or human 

environment. BSEE may require you to 

do a site-specific study (see §250.177(a)). 

(c) When necessary for the installation of safety or environmental protection equipment; 

(d) When necessary to carry out the 

requirements of NEPA or to conduct an 

environmental analysis; or 

(e) When necessary to allow for inordinate delays encountered in obtaining 

required permits or consents, including 

administrative or judicial challenges 

or appeals. 

§ 250.173 When may the Regional Supervisor direct an SOO or SOP? 

The Regional Supervisor may direct 

a suspension when: 

(a) You failed to comply with an applicable law, regulation, order, or provision of a lease or permit; or 

(b) The suspension is in the interest 

of National security or defense. 

§ 250.174 When may the Regional Supervisor grant or direct an SOP? 

The Regional Supervisor may grant 

or direct an SOP when the suspension 

is in the National interest, and it is 

necessary because the suspension will 

meet one of the following criteria: 

(a) It will allow you to properly develop a lease, including time to construct and install production facilities; 

(b) It will allow you time to obtain 

adequate transportation facilities; 

(c) It will allow you time to enter a 

sales contract for oil, gas, or sulphur. 

You must show that you are making an 

effort to enter into the contract(s); or 

(d) It will avoid continued operations 

that would result in premature abandonment of a producing well(s). 

§ 250.175 When may the Regional Supervisor grant an SOO? 

(a) The Regional Supervisor may 

grant an SOO when necessary to allow 

you time to begin drilling or other operations when you are prevented by 

reasons beyond your control, such as 

unexpected weather, unavoidable accidents, or drilling rig delays. 

(b) The Regional Supervisor may 

grant an SOO when all of the following 

conditions are met: 

(1) The lease was issued with a primary lease term of 5 years, or with a 

primary term of 8 years with a requirement to drill within 5 years; 

(2) Before the end of the third year of 

the primary term, you or your predecessor in interest must have acquired 

and interpreted geophysical information that indicates: 

(i) The presence of a salt sheet; 

(ii) That all or a portion of a potential hydrocarbon-bearing formation 

may lie beneath or adjacent to the salt 

sheet; and 

(iii) The salt sheet interferes with 

identification of the potential hydrocarbon-bearing formation. 

(3) The interpreted geophysical information required under paragraph (b)(2) 

of this section must include full 3–D 

depth migration beneath the salt sheet 

and over the entire lease area. 

(4) Before requesting the suspension, 

you have conducted or are conducting 

additional data processing or interpretation of the geophysical information 

with the objective of identifying a potential hydrocarbon-bearing formation. 

(5) You demonstrate that additional 

time is necessary to: 

(i) Complete current processing or interpretation of existing geophysical 

data or information; 

(ii) Acquire, process, or interpret new 

geophysical data or information; or 

(iii) Drill into the potential hydrocarbon-bearing formation identified as 

a result of the activities conducted in 

paragraphs (b)(2), (b)(4), and (b)(5) of 

this section. 

(c) The Regional Supervisor may 

grant an SOO to conduct additional geological and geophysical data analysis 

that may lead to the drilling of a well 

below 25,000 feet true vertical depth 

below the datum at mean sea level 

(TVD SS) when all of the following 

conditions are met: 

(1) The lease was issued with a primary lease term of: 

(i) Five years; or 

(ii) Eight years with a requirement 

to drill within 5 years. 

(2) Before the end of the fifth year of 

the primary term, you or your predecessor in interest must have acquired 


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§ 250.176 30 CFR Ch. II (7–1–13 Edition) 

and interpreted geophysical information that: 

(i) Indicates that all or a portion of a 

potential hydrocarbon-bearing formation lies below 25,000 feet TVD SS; and 

(ii) Includes full 3–D depth migration 

over the entire lease area. 

(3) Before requesting the suspension, 

you have conducted or are conducting 

additional data processing or interpretation of the geophysical information 

with the objective of identifying a potential hydrocarbon-bearing geologic 

structure or stratigraphic trap lying 

below 25,000 feet TVD SS. 

(4) You demonstrate that additional 

time is necessary to: 

(i) Complete current processing or interpretation of existing geophysical 

data or information; 

(ii) Acquire, process, or interpret new 

geophysical or geological data or information that would affect the decision 

to drill the same geologic structure or 

stratigraphic trap, as determined by 

the Regional Supervisor, identified in 

paragraphs (c)(2) and (c)(3) of this section; or 

(iii) Drill a well below 25,000 feet TVD 

SS into the geologic structure or stratigraphic trap identified as a result of 

the activities conducted in paragraphs 

(c)(2), (c)(3), and (c)(4)(i) and (ii) of this 

section. 

§ 250.176 Does a suspension affect my 

royalty payment? 

A directed suspension may affect the 

payment of rental or royalties for the 

lease as provided in 30 CFR 1218.154. 

§ 250.177 What additional requirements may the Regional Supervisor 

order for a suspension? 

If BSEE grants or directs a suspension under paragraph §250.172(b), the 

Regional Supervisor may require you 

to: 

(a) Conduct a site-specific study. 

(1) The Regional Supervisor must approve or prescribe the scope for any 

site-specific study that you perform. 

(2) The study must evaluate the 

cause of the hazard, the potential damage, and the available mitigation 

measures. 

(3) You must pay for the study unless 

you request, and the Regional Supervisor agrees to arrange, payment by 

another party. 

(4) You must furnish copies and results of the study to the Regional Supervisor. 

(5) BSEE will make the results available to other interested parties and to 

the public. 

(6) The Regional Supervisor will use 

the results of the study and any other 

information that becomes available: 

(i) To decide if the suspension can be 

lifted; and 

(ii) To determine any actions that 

you must take to mitigate or avoid any 

damage to the environment, life, or 

property. 

(b) Submit a revised Exploration 

Plan (including any required mitigating measures); 

(c) Submit a revised Development 

and Production Plan (including any required mitigating measures); or 

(d) Submit a revised Development 

Operations Coordination Document according to 30 CFR part 550, subpart B. 

PRIMARY LEASE REQUIREMENTS, LEASE

TERM EXTENSIONS, AND LEASE CANCELLATIONS

§ 250.180 What am I required to do to 

keep my lease term in effect? 

(a) If your lease is in its primary 

term: 

(1) You must submit a report to the 

District Manager according to paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases during the last 

180 days of the primary term, and 

whenever production resumes during 

the last 180 days of the primary term. 

(2) Your lease expires at the end of 

its primary term unless you are conducting operations on your lease (see 30 

CFR part 556). For purposes of this section, the term operations means, drilling, well-reworking, or production in 

paying quantities. The objective of the 

drilling or well-reworking must be to 

establish production in paying quantities on the lease. 

(b) If you stop conducting operations 

during the last 180 days of your primary lease term, your lease will expire 

unless you either resume operations or 

receive an SOO or an SOP from the Regional Supervisor under §250.172, 

§250.173, §250.174, or §250.175 before the 


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Safety & Environmental Enforcement, Interior § 250.186 

end of the 180th day after you stop operations. 

(c) If you extend your lease term 

under paragraph (b) of this section, you 

must pay rental or minimum royalty, 

as appropriate, for each year or part of 

the year during which your lease continues in force beyond the end of the 

primary lease term. 

(d) If you stop conducting operations 

on a lease that has continued beyond 

its primary term, your lease will expire 

unless you resume operations or receive an SOO or an SOP from the Regional Supervisor under §250.172, 

§250.173, §250.174, or §250.175 before the 

end of the 180th day after you stop operations. 

(e) You may ask the Regional Supervisor to allow you more than 180 days 

to resume operations on a lease continued beyond its primary term when operating conditions warrant. The request must be in writing and explain 

the operating conditions that warrant 

a longer period. In allowing additional 

time, the Regional Supervisor must determine that the longer period is in the 

National interest, and it conserves resources, prevents waste, or protects 

correlative rights. 

(f) When you begin conducting operations on a lease that has continued 

beyond its primary term, you must immediately notify the District Manager 

either orally or by fax or e-mail and 

follow up with a written report according to paragraph (g) of this section. 

(g) If your lease is continued beyond 

its primary term, you must submit a 

report to the District Manager under 

paragraphs (h) and (i) of this section 

whenever production begins initially, 

whenever production ceases, whenever 

production resumes before the end of 

the 180-day period after having ceased, 

or whenever drilling or well-reworking 

operations begin before the end of the 

180-day period. 

(h) The reports required by paragraphs (a) and (g) of this section must 

contain: 

(1) Name of lessee or operator; 

(2) The well number, lease number, 

area, and block; 

(3) As appropriate, the unit agreement name and number; and 

(4) A description of the operation and 

pertinent dates. 

(i) You must submit the reports required by paragraphs (a) and (g) of this 

section within the following timeframes: 

(1) Initialization of production—within 5 days of initial production. 

(2) Cessation of production—within 15 

days after the first full month of zero 

production. 

(3) Resumption of production—within 

5 days of resuming production after 

ceasing production under paragraph 

(i)(2) of this section. 

(4) Drilling or well reworking operations—within 5 days of beginning and 

completing the leaseholding operations. 

(j) For leases continued beyond the 

primary term, you must immediately 

report to the District Manager if operations do not begin before the end of 

the 180-day period. 

§§ 250.181–250.185 [Reserved] 

INFORMATION AND REPORTING

REQUIREMENTS

§ 250.186 What reporting information 

and report forms must I submit? 

(a) You must submit information and 

reports as BSEE requires. 

(1) You may obtain copies of forms 

from, and submit completed forms to, 

the District Manager or Regional Supervisor. 

(2) Instead of paper copies of forms 

available from the District Manager or 

Regional Supervisor, you may use your 

own computer-generated forms that 

are equal in size to BSEE’s forms. You 

must arrange the data on your form 

identical to the BSEE form. If you generate your own form and it omits 

terms and conditions contained on the 

official BSEE form, we will consider it 

to contain the omitted terms and conditions. 

(3) You may submit digital data when 

the Region/District is equipped to accept it. 

(b) When BSEE specifies, you must 

include, for public information, an additional copy of such reports. 

(1) You must mark it Public Information 

(2) You must include all required information, except information exempt 

from public disclosure under §250.197 or 


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§ 250.187 30 CFR Ch. II (7–1–13 Edition) 

otherwise exempt from public disclosure under law or regulation. 

§ 250.187 What are BSEE’s incident reporting requirements? 

(a) You must report all incidents listed in §250.188(a) and (b) to the District 

Manager. The specific reporting requirements for these incidents are contained in §§250.189 and 250.190. 

(b) These reporting requirements 

apply to incidents that occur on the 

area covered by your lease, right-of-use 

and easement, pipeline right-of-way, or 

other permit issued by BOEM or BSEE, 

and that are related to operations resulting from the exercise of your rights 

under your lease, right-of-use and easement, pipeline right-of-way, or permit. 

(c) Nothing in this subpart relieves 

you from making notifications and reports of incidents that may be required 

by other regulatory agencies. 

(d) You must report all spills of oil or 

other liquid pollutants in accordance 

with 30 CFR 254.46. 

§ 250.188 What incidents must I report 

to BSEE and when must I report 

them? 

(a) You must report the following incidents to the District Manager immediately via oral communication, and 

provide a written follow-up report 

(hard copy or electronically transmitted) within 15 calendar days after 

the incident: 

(1) All fatalities. 

(2) All injuries that require the evacuation of the injured person(s) from the 

facility to shore or to another offshore 

facility. 

(3) All losses of well control. ‘‘Loss of 

well control’’ means: 

(i) Uncontrolled flow of formation or 

other fluids. The flow may be to an exposed formation (an underground blowout) or at the surface (a surface blowout); 

(ii) Flow through a diverter; or 

(iii) Uncontrolled flow resulting from 

a failure of surface equipment or procedures. 

(4) All fires and explosions. 

(5) All reportable releases of hydrogen sulfide (H2S) gas, as defined in 

§250.490(l). 

(6) All collisions that result in property or equipment damage greater than 

$25,000. ‘‘Collision’’ means the act of a 

moving vessel (including an aircraft) 

striking another vessel, or striking a 

stationary vessel or object (e.g., a boat 

striking a drilling rig or platform). 

‘‘Property or equipment damage’’ 

means the cost of labor and material to 

restore all affected items to their condition before the damage, including, 

but not limited to, the OCS facility, a 

vessel, helicopter, or equipment. It 

does not include the cost of salvage, 

cleaning, gas-freeing, dry docking, or 

demurrage. 

(7) All incidents involving structural 

damage to an OCS facility. ‘‘Structural 

damage’’ means damage severe enough 

so that operations on the facility cannot continue until repairs are made. 

(8) All incidents involving crane or 

personnel/material handling operations. 

(9) All incidents that damage or disable safety systems or equipment (including firefighting systems). 

(b) You must provide a written report 

of the following incidents to the District Manager within 15 calendar days 

after the incident: 

(1) Any injuries that result in one or 

more days away from work or one or 

more days on restricted work or job 

transfer. One or more days means the 

injured person was not able to return 

to work or to all of their normal duties 

the day after the injury occurred; 

(2) All gas releases that initiate 

equipment or process shutdown; 

(3) All incidents that require operations personnel on the facility to muster for evacuation for reasons not related to weather or drills; 

(4) All other incidents, not listed in 

paragraph (a) of this section, resulting 

in property or equipment damage 

greater than $25,000. 

§ 250.189 Reporting requirements for 

incidents requiring immediate notification. 

For an incident requiring immediate 

notification under §250.188(a), you must 

notify the District Manager via oral 

communication immediately after aiding the injured and stabilizing the situation. Your oral communication must 

provide the following information: 

(a) Date and time of occurrence; 


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Safety & Environmental Enforcement, Interior § 250.192 

(b) Operator, and operator representative’s, name and telephone number; 

(c) Contractor, and contractor representative’s name and telephone number (if a contractor is involved in the 

incident or injury/fatality); 

(d) Lease number, OCS area, and 

block; 

(e) Platform/facility name and number, or pipeline segment number; 

(f) Type of incident or injury/fatality; 

(g) Operation or activity at time of 

incident (i.e., drilling, production, 

workover, completion, pipeline, crane, 

etc.); and 

(h) Description of the incident, damage, or injury/fatality. 

§ 250.190 Reporting requirements for 

incidents requiring written notification. 

(a) For any incident covered under 

§250.188, you must submit a written report within 15 calendar days after the 

incident to the District Manager. The 

report must contain the following information: 

(1) Date and time of occurrence; 

(2) Operator, and operator representative’s name and telephone number; 

(3) Contractor, and contractor representative’s name and telephone number (if a contractor is involved in the 

incident or injury); 

(4) Lease number, OCS area, and 

block; 

(5) Platform/facility name and number, or pipeline segment number; 

(6) Type of incident or injury; 

(7) Operation or activity at time of 

incident (i.e., drilling, production, 

workover, completion, pipeline, crane 

etc.); 

(8) Description of incident, damage, 

or injury (including days away from 

work, restricted work or job transfer), 

and any corrective action taken; and 

(9) Property or equipment damage estimate (in U.S. dollars). 

(b) You may submit a report or form 

prepared for another agency in lieu of 

the written report required by paragraph (a) of this section, provided the 

report or form contains all required information. 

(c) The District Manager may require 

you to submit additional information 

about an incident on a case-by-case 

basis. 

§ 250.191 How does BSEE conduct incident investigations? 

Any investigation that BSEE conducts under the authority of sections 

22(d)(1) and (2) of the Act (43 U.S.C. 

1348(d)(1) and (2)) is a fact-finding proceeding with no adverse parties. The 

purpose of the investigation is to prepare a public report that determines 

the cause or causes of the incident. The 

investigation may involve panel meetings conducted by a chairperson appointed by BSEE. The following requirements apply to any panel meetings involving persons giving testimony: 

(a) A person giving testimony may 

have legal or other representative(s) 

present to provide advice or counsel 

while the person is giving testimony. 

The chairperson may require a verbatim transcript to be made of all oral 

testimony. The chairperson also may 

accept a sworn written statement in 

lieu of oral testimony. 

(b) Only panel members, and any experts the panel deems necessary, may 

address questions to any person giving 

testimony. 

(c) The chairperson may issue subpoenas to persons to appear and provide testimony or documents at a panel 

meeting. A subpoena may not require a 

person to attend a panel meeting held 

at a location more than 100 miles from 

where a subpoena is served. 

(d) Any person giving testimony may 

request compensation for mileage, and 

fees for services, within 90 days after 

the panel meeting. The compensated 

expenses must be similar to mileage 

and fees the U.S. District Courts allow. 

§ 250.192 What reports and statistics 

must I submit relating to a hurricane, earthquake, or other natural 

occurrence? 

(a) You must submit evacuation statistics to the Regional Supervisor for a 

natural occurrence, such as a hurricane, a tropical storm, or an earthquake. Statistics include facilities and 

rigs evacuated and the amount of production shut-in for gas and oil. You 

must: 

(1) Submit the statistics by fax or email (for activities in the BSEE GOM 

OCS Region, use Form BSEE–0132) as 


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§ 250.193 30 CFR Ch. II (7–1–13 Edition) 

soon as possible when evacuation occurs. In lieu of submitting your statistics by fax or e-mail, you may submit 

them electronically in accordance with 

30 CFR 250.186(a)(3); 

(2) Submit the statistics on a daily 

basis by 11 a.m., as conditions allow, 

during the period of shut-in and evacuation; 

(3) Inform BSEE when you resume 

production; and 

(4) Submit the statistics either by 

BSEE district, or the total figures for 

your operations in a BSEE region. 

(b) If your facility, production equipment, or pipeline is damaged by a natural occurrence, you must: 

(1) Submit an initial damage report 

to the Regional Supervisor within 48 

hours after you complete your initial 

evaluation of the damage. You must 

use Form BSEE–0143, Facility/Equipment Damage Report, to make this and 

all subsequent reports. In lieu of submitting Form BSEE–0143 by fax or email, you may submit the damage report electronically in accordance with 

30 CFR 250.186(a)(3). In the report, you 

must: 

(i) Name the items damaged (e.g., 

platform or other structure, production 

equipment, pipeline); 

(ii) Describe the damage and assess 

the extent of the damage (major, medium, minor); and 

(iii) Estimate the time it will take to 

replace or repair each damaged structure and piece of equipment and return 

it to service. The initial estimate need 

not be provided on the form until availability of hardware and repair capability has been established (not to exceed 30 days from your initial report). 

(2) Submit subsequent reports 

monthly and immediately whenever information submitted in previous reports changes until the damaged structure or equipment is returned to service. In the final report, you must provide the date the item was returned to 

service. 

§ 250.193 Reports and investigations of 

possible violations. 

(a) Any person may report to BSEE 

any hazardous or unsafe working condition on any facility engaged in OCS 

activities, and any possible violation or 

failure to comply with: 

(1) Any provision of the Act, 

(2) Any provision of a lease, approved 

plan, or permit issued under the Act, 

(3) Any provision of any regulation or 

order issued under the Act, or 

(4) Any other Federal law relating to 

safety of offshore oil and gas operations. 

(b) To make a report under this section, a person is not required to know 

whether any legal requirement listed 

in paragraph (a) of this section has 

been violated. 

(c) When BSEE receives a report of a 

possible violation, or when a BSEE employee detects a possible violation, 

BSEE will investigate according to 

BSEE procedures and notify any other 

Federal agency(ies) for further investigation, as appropriate. 

(d) BSEE investigations of possible 

violations may include: 

(1) Conducting interviews of personnel; 

(2) Requiring the prompt production 

of documents, data, and other evidence; 

(3) Requiring the preservation of all 

relevant evidence and access for BSEE 

investigators to such evidence; and 

(4) Taking other actions and imposing other requirements as necessary to 

investigate possible violations and assure an orderly investigation. 

(e)(1) Reports should contain sufficient credible information to establish 

a reasonable basis for BSEE to investigate whether a violation or other 

hazardous or unsafe working condition 

exists. 

(2) To report hazardous or unsafe 

working conditions or a possible violation: 

(i) Contact BSEE by: 

(A) Phone at 1–877–440–0173 (BSEE 

Toll-free Safety Hotline), 

(B) Internet at www.bsee.gov, or 

(C) Mail to: U.S. DOI/BSEE, 1849 C 

Street NW., Mail Stop 5438, Herndon, 

VA 20240 Attention: IRU Hotline Operations. 

(ii) Include the following items in the 

report: 

(A) Name, address, and telephone 

number should be provided if you do 

not want to remain anonymous; 

(B) The specific concern, provision or 

Federal law, if known, referenced in (a) 

that a person violated or with which a 

person failed to comply; and 


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Safety & Environmental Enforcement, Interior § 250.197 

(C) Any other facts, data, and applicable information. 

(f) When a possible violation is reported, BSEE will protect a person’s 

identity to the extent authorized by 

law. 

[78 FR 20439, Apr. 5, 2013] 

§ 250.194 How must I protect archaeological resources? 

(a)–(b) [Reserved] 

(c) If you discover any archaeological 

resource while conducting operations 

in the lease or right-of-way area, you 

must immediately halt operations 

within the area of the discovery and report the discovery to the BSEE Regional Director. If investigations determine that the resource is significant, 

the Regional Director will tell you how 

to protect it. 

§ 250.195 What notification does BSEE 

require on the production status of 

wells? 

You must notify the appropriate 

BSEE District Manager when you successfully complete or recomplete a well 

for production. You must: 

(a) Notify the District Manager within 5 working days of placing the well in 

a production status. You must confirm 

oral notification by telefax or e-mail 

within those 5 working days. 

(b) Provide the following information 

in your notification: 

(1) Lessee or operator name; 

(2) Well number, lease number, and 

OCS area and block designations; 

(3) Date you placed the well on production (indicate whether or not this is 

first production on the lease); 

(4) Type of production; and 

(5) Measured depth of the production 

interval. 

§ 250.196 Reimbursements for reproduction and processing costs. 

(a) BSEE will reimburse you for costs 

of reproducing data and information 

that the Regional Director requests if: 

(1) You deliver geophysical and geological (G&G) data and information to 

BSEE for the Regional Director to inspect or select and retain; 

(2) BSEE receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and 

(3) The cost is at your lowest rate or 

at the lowest commercial rate established in the area, whichever is less. 

(b) BSEE will reimburse you for the 

costs of processing geophysical information (that does not include cost of 

data acquisition): 

(1) If, at the request of the Regional 

Director, you processed the geophysical data or information in a form 

or manner other than that used in the 

normal conduct of business; or 

(2) If you collected the information 

under a permit that BSEE issued to 

you before October 1, 1985, and the Regional Director requests and retains 

the information. 

(c) When you request reimbursement, 

you must identify reproduction and 

processing costs separately from acquisition costs. 

(d) BSEE will not reimburse you for 

data acquisition costs or for the costs 

of analyzing or processing geological 

information or interpreting geological 

or geophysical information. 

§ 250.197 Data and information to be 

made available to the public or for 

limited inspection. 

BSEE will protect data and information that you submit under this part, 

and 30 CFR part 203, as described in 

this section. Paragraphs (a) and (b) of 

this section describe what data and information will be made available to the 

public without the consent of the lessee, under what circumstances, and in 

what time period. Paragraph (c) of this 

section describes what data and information will be made available for limited inspection without the consent of 

the lessee, and under what circumstances. 

(a) All data and information you submit on BSEE forms will be made available to the public upon submission, except as specified in the following table: 


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§ 250.197 30 CFR Ch. II (7–1–13 Edition) 

On form . . . Data and information not immediately 

available are . . . 

Excepted data will be made available 

. . . 

(1) BSEE–0123, Application for Permit to 

Drill, 

Items 15, 16, 22 through 25, When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. 

(2) BSEE–0123S, Supplemental APD Information Sheet, Items 3, 7, 8, 15 and 17, When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. 

(3) BSEE–0124, Application for Permit to 

Modify, 

Item 17, When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. 

(4) BSEE–0125, End of Operations Report, Items 12, 13, 17, 21, 22, 26 through 38, When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. However, items 33 through 38 will not be 

released when the well goes on production unless the period of time in 

the table in paragraph (b) has expired. 

(5) BSEE–0126, Well Potential Test Report, Item 101, 2 years after you submit it. 

(6) [Reserved] 

(7) BSEE–0133 Well Activity Report, Item 10 Fields [WELLBORE START 

DATE, TD DATE, OP STATUS, END 

DATE, MD, TVD, AND MW PPG]. 

Item 11 Fields [WELLBORE START 

DATE, TD DATE, PLUGBACK DATE, 

FINAL MD, AND FINAL TVD] and 

Items 12 through 15, 

When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. 

(8) BSEE–0133S Open Hole Data Report, Boxes 7 and 8, When the well goes on production or according to the table in paragraph (b) of 

this section, whichever is earlier. 

(9) [Reserved] 

(10) [Reserved] 

(b) BSEE will release lease and permit data and information that you submit and BSEE retains, but that are not normally submitted on BSEE forms, 

according to the following table: 

If . . . BSEE will release . . . At this time . . . Special provisions . . . 

(1) The Director determines 

that data and information are 

needed for specific scientific 

or research purposes for the 

Government, 

Geophysical data, Geological 

data Interpreted G&G information, Processed G&G information, Analyzed geological information, 

At any time, BSEE will release data and 

information only if release 

would further the National 

interest without unduly 

damaging the competitive 

position of the lessee. 

(2) Data or information is collected with high-resolution 

systems (e.g., bathymetry, 

side-scan sonar, subbottom 

profiler, and magnetometer) 

to comply with safety or environmental protection requirements, 

Geophysical data, Geological 

data, Interpreted G&G information, Processed geological information, Analyzed 

geological information, 

60 days after BSEE receives 

the data or information, if 

the Regional Supervisor 

deems it necessary, 

BSEE will release the data 

and information earlier than 

60 days if the Regional Supervisor determines it is 

needed by affected States 

to make decisions under 30 

CFR 550, subpart B. The 

Regional Supervisor will reconsider earlier release if 

you satisfy him/her that it 

would unduly damage your 

competitive position. 

(3) Your lease is no longer in 

effect, 

Geophysical data, Geological 

data, Processed G&G information Interpreted G&G information, Analyzed geological information, 

When your lease terminates, This release time applies only 

if the provisions in this table 

governing high-resolution 

systems and the provisions 

in 30 CFR 552.7 do not 

apply. The release time applies to the geophysical 

data and information only if 

acquired postlease for a 

lessee’s exclusive use. 


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Safety & Environmental Enforcement, Interior § 250.198 

If . . . BSEE will release . . . At this time . . . Special provisions . . . 

(4) Your lease is still in effect, Geophysical data, Processed 

geophysical information, Interpreted G&G information, 

10 years after you submit the 

data and information, 

This release time applies only 

if the provisions in this table 

governing high-resolution 

systems and the provisions 

in 30 CFR 552.7 do not 

apply. This release time applies to the geophysical 

data and information only if 

acquired postlease for a 

lessee’s exclusive use. 

(5) Your lease is still in effect 

and within the primary term 

specified in the lease, 

Geological data, Analyzed geological information, 2 years after the required 

submittal date or 60 days 

after a lease sale if any 

portion of an offered lease 

is within 50 miles of a well, 

whichever is later, 

These release times apply 

only if the provisions in this 

table governing high-resolution systems and the provisions in 30 CFR 552.7 do 

not apply. If the primary 

term specified in the lease 

is extended under the 

heading of ‘‘Suspensions’’ 

in this subpart, the extension applies to this provision. 

(6) Your lease is in effect and 

beyond the primary term 

specified in the lease, 

Geological data, Analyzed geological information, 2 years after the required 

submittal date, 

None. 

(7) Data or information is submitted on well operations, Descriptions of downhole locations, operations, and 

equipment, 

When the well goes on production or when geological 

data is released according 

to §§ 250.197(b)(5) and 

(b)(6), whichever occurs 

earlier, 

Directional survey data may 

be released earlier to the 

owner of an adjacent lease 

according to Subpart D of 

this part. 

(8) Data and information are 

obtained from beneath unleased land as a result of a 

well deviation that has not 

been approved by the District Manager or Regional 

Supervisor, 

Any data or information obtained, At any time, None. 

(9) Except for high-resolution 

data and information released under paragraph 

(b)(2) of this section data 

and information acquired by 

a permit under 30 CFR part 

551 are submitted by a lessee under 30 CFR part 203, 

30 CFR part 250, or 30 CFR 

part 550, 

G&G data, analyzed geological information, processed 

and interpreted G&G information, 

Geological data and information: 10 years after BOEM 

issues the permit; Geophysical data: 50 years 

after BOEM issues the permit; Geophysical information: 25 years after BOEM 

issues the permit, 

None. 

(c) BSEE may allow limited inspection, but only by persons with a direct 

interest in related BSEE decisions and 

issues in specific geographic areas, and 

who agree in writing to its confidentiality, of G&G data and information 

submitted under this part or 30 CFR 

part 203 that BSEE uses to: 

(1) Make unitization determinations 

on two or more leases; 

(2) Make competitive reservoir determinations; 

(3) Ensure proper plans of development for competitive reservoirs; 

(4) Promote operational safety; 

(5) Protect the environment; 

(6) [Reserved]; or 

(7) Determine eligibility for royalty 

relief. 

REFERENCES

§ 250.198 Documents incorporated by 

reference. 

(a) The BSEE is incorporating by reference the documents listed in paragraphs (e) through (k) of this section. 

Paragraphs (e) through (k) identify the 

publishing organization of the documents, the address and phone number 

where you may obtain these documents, and the documents incorporated 

by reference. The Director of the Federal Register has approved the 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.198 30 CFR Ch. II (7–1–13 Edition) 

incorporations by reference according 

to 5 U.S.C. 552(a) and 1 CFR part 51. 

(1) Incorporation by reference of a 

document is limited to the edition of 

the publication that is cited in this 

section. Future amendments or revisions of the document are not included. 

The BSEE will publish any changes to 

a document in the FEDERAL REGISTER

and amend this section. 

(2) The BSEE may make the rule 

amending the document effective without prior opportunity for public comment when BSEE determines: 

(i) That the revisions to a document 

result in safety improvements or represent new industry standard technology and do not impose undue costs 

on the affected parties; and 

(ii) The BSEE meets the requirements for making a rule immediately 

effective under 5 U.S.C. 553. 

(3) The effect of incorporation by reference of a document into the regulations in this part is that the incorporated document is a requirement. 

When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except 

to the extent that the section which incorporates the document by reference 

provides otherwise. When a section in 

this part incorporates part of a document, you are responsible for complying with that part of the document 

as provided in that section. 

(b) The BSEE incorporated each document or specific portion by reference 

in the sections noted. The entire document is incorporated by reference, unless the text of the corresponding sections in this part calls for compliance 

with specific portions of the listed documents. In each instance, the applicable document is the specific edition or 

specific edition and supplement or addendum cited in this section. 

(c) Under §§250.141 and 250.142, you 

may comply with a later edition of a 

specific document incorporated by reference, provided: 

(1) You show that complying with the 

later edition provides a degree of protection, safety, or performance equal 

to or better than would be achieved by 

compliance with the listed edition; and 

(2) You obtain the prior written approval for alternative compliance from 

the authorized BSEE official. 

(d) You may inspect these documents 

at the Bureau of Safety and Environmental Enforcement, 381 Elden Street, 

Room 3313, Herndon, Virginia 20170; 

phone: 703–787–1587; or at the National 

Archives and Records Administration 

(NARA). For information on the availability of this material at NARA, call 

202–741–6030, or go to: http://www.archives.gov/federallregister/codel

oflfederallregulations/ibrllocations.

html. 

(e) American Concrete Institute 

(ACI), ACI Standards, P. O. Box 9094, 

Farmington Hill, MI 48333–9094: http:// 

www.concrete.org; phone: 248–848–3700: 

(1) ACI Standard 318–95, Building 

Code Requirements for Reinforced Concrete (ACI 318–95), incorporated by reference at §250.901. 

(2) ACI 318R–95, Commentary on 

Building Code Requirements for Reinforced Concrete, incorporated by reference at §250.901. 

(3) ACI 357R–84, Guide for the Design 

and Construction of Fixed Offshore 

Concrete Structures, 1984; reapproved 

1997, incorporated by reference at 

§250.901. 

(f) American Institute of Steel Construction, Inc. (AISC), AISC Standards, 

One East Wacker Drive, Suite 700, Chicago, IL 60601–1802; http://www.aisc.org; 

phone: 312–670–2400: 

(1) ANSI/AISC 360–05, Specification 

for Structural Steel Buildings incorporated by reference at §250.901. 

(2) [Reserved] 

(g) American National Standards Institute (ANSI), ANSI/ASME Codes, 

ATTN: Sales Department, 25 West 43rd 

Street, 4th Floor, New York, NY 10036; 

http://www.ansi.org; phone: 212–642–4900; 

and/or American Society of Mechanical 

Engineers (ASME), 22 Law Drive, P.O. 

Box 2900, Fairfield, NJ 07007–2900; http:// 

www.asme.org; phone: 973–882–5155: 

(1) ANSI/ASME Boiler and Pressure 

Vessel Code, Section I, Rules for Construction of Power Boilers; including 

Appendices, 2004 Edition; and July 1, 

2005 Addenda, and all Section I Interpretations Volume 55, incorporated by 

reference at §§250.803 and 250.1629; 


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Safety & Environmental Enforcement, Interior § 250.198 

(2) ANSI/ASME Boiler and Pressure 

Vessel Code, Section IV, Rules for Construction of Heating Boilers; including 

Appendices 1, 2, 3, 5, 6, and Non-mandatory Appendices B, C, D, E, F, H, I, K, 

L, and M, and the Guide to Manufacturers Data Report Forms, 2004 Edition; July 1, 2005 Addenda, and all Section IV Interpretations Volume 55, incorporated by reference at §§250.803 and 

250.1629; 

(3) ANSI/ASME Boiler and Pressure 

Vessel Code, Section VIII, Rules for 

Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; July 1, 2005 

Addenda, Divisions 1 and 2, and all Section VIII Interpretations Volumes 54 

and 55, incorporated by reference at 

§§250.803 and 250.1629; 

(4) ANSI/ASME B 16.5–2003, Pipe 

Flanges and Flanged Fittings incorporated by reference at §250.1002; 

(5) ANSI/ASME B 31.8–2003, Gas 

Transmission and Distribution Piping 

Systems incorporated by reference at 

§250.1002; 

(6) ANSI/ASME SPPE–1–1994, Quality 

Assurance and Certification of Safety 

and Pollution Prevention Equipment 

Used in Offshore Oil and Gas Operations, incorporated by reference at 

§250.806; 

(7) ANSI/ASME SPPE–1d–1996 Addenda, Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil 

and Gas Operations, incorporated by 

reference at §250.806; 

(8) ANSI Z88.2–1992, American National Standard for Respiratory Protection, incorporated by reference at, 

§250.490. 

(h) American Petroleum Institute 

(API), API Recommended Practices 

(RP), Specs, Standards, Manual of Petroleum Measurement Standards 

(MPMS) chapters, 1220 L Street, NW., 

Washington, DC 20005–4070; http:// 

www.api.org; phone: 202–682–8000: 

(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 

2006; incorporated by reference at 

§§250.803 and 250.1629; 

(2) API Bulletin 2INT–DG, Interim 

Guidance for Design of Offshore Structures for Hurricane Conditions, May 

2007; incorporated by reference at 

§250.901; 

(3) API Bulletin 2INT–EX, Interim 

Guidance for Assessment of Existing 

Offshore Structures for Hurricane Conditions, May 2007; incorporated by reference at §250.901; 

(4) API Bulletin 2INT–MET, Interim 

Guidance on Hurricane Conditions in 

the Gulf of Mexico, May 2007; incorporated by reference at §250.901; 

(5) API MPMS, Chapter 1—Vocabulary, Second Edition, July 1994; incorporated by reference at §250.1201; 

(6) API MPMS, Chapter 2—Tank Calibration, Section 2A—Measurement and 

Calibration of Upright Cylindrical 

Tanks by the Manual Tank Strapping 

Method, First Edition, February 1995; 

reaffirmed February 2007; incorporated 

by reference at §250.1202; 

(7) API MPMS, Chapter 2—Tank Calibration, Section 2B—Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989; reaffirmed, December 

2007; incorporated by reference at 

§250.1202; 

(8) API MPMS, Chapter 3—Tank 

Gauging, Section 1A—Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second 

Edition, August 2005; incorporated by 

reference at §250.1202; 

(9) API MPMS, Chapter 3—Tank 

Gauging, Section 1B—Standard Practice for Level Measurement of Liquid 

Hydrocarbons in Stationary Tanks by 

Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, October 

2006; incorporated by reference at 

§250.1202; 

(10) API MPMS, Chapter 4—Proving 

Systems, Section 1—Introduction, 

Third Edition, February 2005; incorporated by reference at §250.1202; 

(11) API MPMS, Chapter 4—Proving 

Systems, Section 2—Displacement 

Provers, Third Edition, September 2003; 

incorporated by reference at §250.1202; 

(12) API MPMS, Chapter 4—Proving 

Systems, Section 4—Tank Provers, 

Second Edition, May 1998, reaffirmed 

November 2005; incorporated by reference at §250.1202; 

(13) API MPMS, Chapter 4—Proving 

Systems, Section 5—Master-Meter 


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§ 250.198 30 CFR Ch. II (7–1–13 Edition) 

Provers, Second Edition, May 2000, reaffirmed: August 2005; incorporated by 

reference at §250.1202; 

(14) API MPMS, Chapter 4—Proving 

Systems, Section 6—Pulse Interpolation, Second Edition, May 1999; reaffirmed 2003; incorporated by reference at §250.1202; 

(15) API MPMS, Chapter 4—Proving 

Systems, Section 7—Field Standard 

Test Measures, Second Edition, December 1998; reaffirmed 2003; incorporated 

by reference at §250.1202; 

(16) API MPMS, Chapter 5—Metering, 

Section 1—General Considerations for 

Measurement by Meters, Fourth Edition, September 2005; incorporated by 

reference at §250.1202; 

(17) API MPMS, Chapter 5—Metering, 

Section 2—Measurement of Liquid Hydrocarbons by Displacement Meters, 

Third Edition, September 2005; incorporated by reference at §250.1202; 

(18) API MPMS Chapter 5—Metering, 

Section 3—Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth 

Edition, September 2005; incorporated 

by reference at §250.1202; 

(19) API MPMS, Chapter 5—Metering, 

Section 4—Accessory Equipment for 

Liquid Meters, Fourth Edition, September 2005; incorporated by reference 

at §250.1202; 

(20) API MPMS, Chapter 5—Metering, 

Section 5—Fidelity and Security of 

Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005; incorporated by reference at 

§250.1202; 

(21) API MPMS, Chapter 6—Metering 

Assemblies, Section 1—Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; reaffirmed, April 2007; incorporated by 

reference at §250.1202; 

(22) API MPMS, Chapter 6—Metering 

Assemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991; 

reaffirmed, February 2007; incorporated 

by reference at §250.1202; 

(23) API MPMS, Chapter 6—Metering 

Assemblies, Section 7—Metering Viscous Hydrocarbons, Second Edition, 

May 1991; reaffirmed, April 2007; incorporated by reference at §250.1202; 

(24) API MPMS, Chapter 7—Temperature Determination, First Edition, 

June 2001; reaffirmed, March 2007; incorporated by reference at §250.1202; 

(25) API MPMS, Chapter 8—Sampling, Section 1—Standard Practice for 

Manual Sampling of Petroleum and Petroleum Products, Third Edition, October 1995; reaffirmed, March 2006; incorporated by reference at §250.1202; 

(26) API MPMS, Chapter 8—Sampling, Section 2—Standard Practice for 

Automatic Sampling of Liquid Petroleum and Petroleum Products, Second 

Edition, October 1995; reaffirmed, June 

2005; incorporated by reference at 

§250.1202; 

(27) API MPMS, Chapter 9—Density 

Determination, Section 1—Standard 

Test Method for Density, Relative Density (Specific Gravity), or API Gravity 

of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, 

Second Edition, December 2002; reaffirmed October 2005; incorporated by 

reference at §250.1202(a)(3) and (l)(4); 

(28) API MPMS, Chapter 9—Density 

Determination, Section 2—Standard 

Test Method for Density or Relative 

Density of Light Hydrocarbons by 

Pressure Hydrometer, Second Edition, 

March 2003; incorporated by reference 

at §250.1202; 

(29) API MPMS, Chapter 10—Sediment and Water, Section 1—Standard 

Test Method for Sediment in Crude 

Oils and Fuel Oils by the Extraction 

Method, Third Edition, November 2007; 

incorporated by reference at §250.1202; 

(30) API MPMS, Chapter 10—Sediment and Water, Section 2—Standard 

Test Method for Water in Crude Oil by 

Distillation, Second Edition, November 

2007; incorporated by reference at 

§250.1202; 

(31) API MPMS, Chapter 10—Sediment and Water, Section 3—Standard 

Test Method for Water and Sediment in 

Crude Oil by the Centrifuge Method 

(Laboratory Procedure), Third Edition, 

May 2008; incorporated by reference at 

§250.1202; 

(32) API MPMS, Chapter 10—Sediment and Water, Section 4—Determination of Water and/or Sediment in 

Crude Oil by the Centrifuge Method 

(Field Procedure), Third Edition, December 1999; incorporated by reference 

at §250.1202; 

(33) API MPMS, Chapter 10—Sediment and Water, Section 9—Standard 

Test Method for Water in Crude Oils by 

Coulometric Karl Fischer Titration, 


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Safety & Environmental Enforcement, Interior § 250.198 

Second Edition, December 2002; reaffirmed 2005; incorporated by reference at §250.1202; 

(34) API MPMS, Chapter 11.1—Volume Correction Factors, Volume 1, 

Table 5A—Generalized Crude Oils and 

JP–4 Correction of Observed API Gravity to API Gravity at 60 °F, and Table 

6A—Generalized Crude Oils and JP–4 

Correction of Volume to 60 °F Against 

API Gravity at 60 °F, API Standard 

2540, First Edition, August 1980; reaffirmed March 1997; incorporated by 

reference at §250.1202; 

(35) API MPMS, Chapter 11.2.2—Compressibility Factors for Hydrocarbons: 

0.350–0.637 Relative Density (60 °F/60 °F) 

and ¥50 °F to 140 °F Metering Temperature, Second Edition, October 1986; 

reaffirmed: December 2007; incorporated by reference at §250.1202; 

(36) API MPMS, Chapter 11—Physical 

Properties Data, Addendum to Section 

2, Part 2—Compressibility Factors for 

Hydrocarbons, Correlation of Vapor 

Pressure for Commercial Natural Gas 

Liquids, First Edition, December 1994; 

reaffirmed, December 2002; incorporated by reference at §250.1202; 

(37) API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 

2—Calculation of Petroleum Quantities 

Using Dynamic Measurement Methods 

and Volumetric Correction Factors, 

Part 1—Introduction, Second Edition, 

May 1995; reaffirmed March 2002; incorporated by reference at §250.1202; 

(38) API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 

2—Calculation of Petroleum Quantities 

Using Dynamic Measurement Methods 

and Volumetric Correction Factors, 

Part 2—Measurement Tickets, Third 

Edition, June 2003; incorporated by reference at §250.1202; 

(39) API MPMS, Chapter 14—Natural 

Gas Fluids Measurement, Section 3— 

Concentric, Square-Edged Orifice Meters, Part 1—General Equations and 

Uncertainty Guidelines, Third Edition, 

September 1990; reaffirmed January 

2003; incorporated by reference at 

§250.1203; 

(40) API MPMS, Chapter 14—Natural 

Gas Fluids Measurement, Section 3— 

Concentric, Square-Edged Orifice Meters, Part 2—Specification and Installation Requirements, Fourth Edition, 

April 2000; reaffirmed March 2006; incorporated by reference at §250.1203; 

(41) API MPMS, Chapter 14—Natural 

Gas Fluids Measurement, Section 3— 

Concentric, Square-Edged Orifice Meters; Part 3—Natural Gas Applications; 

Third Edition, August 1992; Errata 

March 1994, reaffirmed, February 2009; 

incorporated by reference at §250.1203; 

(42) API MPMS, Chapter 14.5/GPA 

Standard 2172–09; Calculation of Gross 

Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas 

Mixtures for Custody Transfer; Third 

Edition, January 2009; incorporated by 

reference at §250.1203; 

(43) API MPMS, Chapter 14—Natural 

Gas Fluids Measurement, Section 6— 

Continuous Density Measurement, Second Edition, April 1991; reaffirmed, 

February 2006; incorporated by reference at §250.1203; 

(44) API MPMS, Chapter 14—Natural 

Gas Fluids Measurement, Section 8— 

Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed, March 2006; incorporated by 

reference at §250.1203; 

(45) API MPMS, Chapter 20—Section 

1—Allocation Measurement, First Edition, September 1993; reaffirmed October 2006; incorporated by reference at 

§250.1202; 

(46) API MPMS, Chapter 21—Flow 

Measurement Using Electronic Metering Systems, Section 1—Electronic Gas 

Measurement, First Edition, August 

1993; reaffirmed, July 2005; incorporated by reference at §250.1203; 

(47) API RP 2A–WSD, Recommended 

Practice for Planning, Designing and 

Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000; Errata 

and Supplement 1, December 2002; Errata and Supplement 2, September 2005; 

Errata and Supplement 3, October 2007; 

incorporated by reference at §§250.901, 

250.908, 250.919, and 250.920; 

(48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth Edition, May 2007; incorporated by reference at §250.108; 

(49) API RP 2FPS, RP for Planning, 

Designing, and Constructing Floating 

Production Systems; First Edition, 

March 2001; incorporated by reference 

at §250.901; 


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§ 250.198 30 CFR Ch. II (7–1–13 Edition) 

(50) API RP 2I, In-Service Inspection 

of Mooring Hardware for Floating 

Structures; Third Edition, April 2008; 

incorporated by reference at §250.901(a) 

and (d); 

(51) API RP 2RD, Recommended 

Practice for Design of Risers for Floating Production Systems (FPSs) and 

Tension-Leg Platforms (TLPs), First 

Edition, June 1998; reaffirmed, May 

2006, Errata, June 2009; incorporated by 

reference at §§250.800; 250.901 and 

250.1002; 

(52) API RP 2SK, Design and Analysis 

of Stationkeeping Systems for Floating Structures, Third Edition, October 

2005, Addendum, May 2008; incorporated 

by reference at §§250.800 and 250.901; 

(53) API RP 2SM, Recommended 

Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, March 2001, Addendum, May 2007; incorporated by reference at §250.901; 

(54) API RP 2T, Recommended Practice for Planning, Designing, and Constructing Tension Leg Platforms, Second Edition, August 1997; incorporated 

by reference at §250.901; 

(55) API RP 14B, Recommended Practice for Design, Installation, Repair 

and Operation of Subsurface Safety 

Valve Systems, Fifth Edition, October 

2005, also available as ISO 10417: 2004, 

(Identical) Petroleum and natural gas 

industries—Subsurface safety valve 

systems—Design, installation, operation and redress; incorporated by reference at §§250.801 and 250.804; 

(56) API RP 14C, Recommended Practice for Analysis, Design, Installation, 

and Testing of Basic Surface Safety 

Systems for Offshore Production Platforms, Seventh Edition, March 2001, reaffirmed: March 2007; incorporated by 

reference at §§250.125, 250.292, 250.802, 

250.803, 250.804, 250.1002, 250.1004, 

250.1628, 250.1629, and 250.1630; 

(57) API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; reaffirmed, March 2007; incorporated by 

reference at §§250.802 and 250.1628; 

(58) API RP 14F, Design, Installation, 

and Maintenance of Electrical Systems 

for Fixed and Floating Offshore Petroleum Facilities for Unclassified and 

Class I, Division 1 and Division 2 Locations, Fifth Edition, July 2008; incorporated by reference at §§250.114, 

250.803, and 250.1629; 

(59) API RP 14FZ, Recommended 

Practice for Design and Installation of 

Electrical Systems for Fixed and 

Floating Offshore Petroleum Facilities 

for Unclassified and Class I, Zone 0, 

Zone 1 and Zone 2 Locations, First Edition, September 2001, reaffirmed: 

March 2007; incorporated by reference 

at §§250.114, 250.803, and 250.1629; 

(60) API RP 14G, Recommended Practice for Fire Prevention and Control on 

Fixed Open-type Offshore Production 

Platforms, Fourth Edition, April 2007; 

incorporated by reference at §§250.803 

and 250.1629; 

(61) API RP 14H, Recommended Practice for Installation, Maintenance and 

Repair of Surface Safety Valves and 

Underwater Safety Valves Offshore, 

Fifth Edition, August 2007; incorporated by reference at §§250.802 and 

250.804; 

(62) API RP 14J, Recommended Practice for Design and Hazards Analysis 

for Offshore Production Facilities, Second Edition, May 2001; reaffirmed: 

March 2007; incorporated by reference 

at §§250.800 and 250.901; 

(63) API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, Third 

Edition, March 1997; reaffirmed September 2004; incorporated by reference 

at §§250.442, 250.446, 250.517, 250.618, and 

250.1708; 

(64) API RP 65, Recommended Practice for Cementing Shallow Water Flow 

Zones in Deepwater Wells, First Edition, September 2002; incorporated by 

reference at §250.415; 

(65) API RP 500, Recommended Practice for Classification of Locations for 

Electrical Installations at Petroleum 

Facilities Classified as Class I, Division 

1 and Division 2, Second Edition, November 1997; reaffirmed November 2002; 

incorporated by reference at §§250.114, 

250.459, 250.802, 250.803, 250.1628, and 

250.1629; 

(66) API RP 505, Recommended Practice for Classification of Locations for 

Electrical Installations at Petroleum 

Facilities Classified as Class I, Zone 0, 

Zone 1, and Zone 2, First Edition, November 1997; reaffirmed November 2002; 


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Safety & Environmental Enforcement, Interior § 250.198 

incorporated by reference at §§250.114, 

250.459, 250.802, 250.803, 250.1628, and 

250.1629; 

(67) API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 

1993; reaffirmed November 2003; incorporated by reference at §250.1202; 

(68) ANSI/API Spec. Q1, Specification 

for Quality Programs for the Petroleum, Petrochemical and Natural Gas 

Industry, ISO TS 29001:2007 (Identical), 

Petroleum, petrochemical and natural 

gas industries—Sector specific requirements—Requirements for product and 

service supply organizations, Eighth 

Edition, December 2007, Effective Date: 

June 15, 2008; incorporated by reference 

at §250.806; 

(69) API Spec. 2C, Specification for 

Offshore Pedestal Mounted Cranes, 

Sixth Edition, March 2004, Effective 

Date: September 2004; incorporated by 

reference at §250.108; 

(70) ANSI/API Spec. 6A, Specification 

for Wellhead and Christmas Tree 

Equipment, Nineteenth Edition, July 

2004; Effective Date: February 1, 2005; 

Contains API Monogram Annex as Part 

of U.S. National Adoption; ISO 

10423:2003 (Modified), Petroleum and 

natural gas industries—Drilling and 

production equipment—Wellhead and 

Christmas tree equipment; Errata 1, 

September 2004, Errata 2, April 2005, 

Errata 3, June 2006, Errata 4, August 

2007, Errata 5, May 2009; Addendum 1, 

February 2008; Addendum 2, 3, and 4, 

December 2008; incorporated by reference at §§250.806 and 250.1002; 

(71) API Spec. 6AV1, Specification for 

Verification Test of Wellhead Surface 

Safety Valves and Underwater Safety 

Valves for Offshore Service, First Edition, February 1, 1996; reaffirmed January 2003; incorporated by reference at 

§250.806; 

(72) ANSI/API Spec. 6D, Specification 

for Pipeline Valves, Twenty-third Edition, April 2008; Effective Date: October 

1, 2008, Errata 1, June 2008; Errata 2, 

November 2008; Errata 3, February 2009; 

Addendum 1, October 2009; Contains 

API Monogram Annex as Part of U.S. 

National Adoption; ISO 14313:2007 

(Identical), Petroleum and natural gas 

industries—Pipeline transportation 

systems—Pipeline valves; incorporated 

by reference at §250.1002; 

(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve 

Equipment, Eleventh Edition, October 

2005, Effective Date: May 1, 2006; also 

available as ISO 10432:2004; incorporated by reference at §250.806; 

(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, Third 

Edition, July 2008; Effective Date: January 1, 2009, Contains API Monogram 

Annex as Part of U.S. National Adoption; ISO 13628–2:2006 (Identical), Petroleum and natural gas industries—Design and operation of subsea production systems—Part 2: Unbonded flexible pipe systems for subsea and marine 

application; incorporated by reference 

at §§250.803, 250.1002, and 250.1007; 

(75) API Standard 2552, USA Standard 

Method for Measurement and Calibration of Spheres and Spheroids, First 

Edition, 1966; reaffirmed, October 2007; 

incorporated by reference at §250.1202; 

(76) API Standard 2555, Method for 

Liquid Calibration of Tanks, First Edition, September 1966; reaffirmed March 

2002; incorporated by reference at 

§250.1202; 

(77) API RP 90, Annular Casing Pressure Management for Offshore Wells, 

First Edition, August 2006, incorporated by reference at §250.518; 

(78) API Standard 65—Part 2, Isolating Potential Flow Zones During 

Well Construction; Second Edition, December 2010; incorporated by reference 

at §250.415(f); 

(79) API RP 75, Recommended Practice for Development of a Safety and 

Environmental Management Program 

for Offshore Operations and Facilities, 

Third Edition, May 2004, Reaffirmed 

May 2008; incorporated by reference at 

§§250.1900, 250.1902, 250.1903, 250.1909, 

250.1920; 

(80) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

4—Proving Systems, Section 8—Operation of Proving Systems; First Edition, reaffirmed March 2007; incorporated by reference at §250.1202(a)(2), 

(a)(3), (f)(1), and (g); 

(81) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

5—Metering, Section 6—Measurement 

of Liquid Hydrocarbons by Coriolis Meters; First Edition, reaffirmed March 

2008; incorporated by reference at 

§250.1202(a)(2) and (3); 


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§ 250.198 30 CFR Ch. II (7–1–13 Edition) 

(82) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

5—Metering, Section 8—Measurement 

of Liquid Hydrocarbons by Ultrasonic 

Flow Meters Using Transit Time Technology; First Edition, February 2005; 

incorporated by reference at 

§250.1202(a)(2) and (3); 

(83) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

11—Physical Properties Data, Section 

1—Temperature and Pressure Volume 

Correction Factors for Generalized 

Crude Oils, Refined Products, and Lubricating Oils; May 2004, (incorporating 

Addendum 1, September 2007); incorporated by reference at §250.1202(a)(2), 

(a)(3), (g), and (l)(4); 

(84) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 3—Proving Reports; First Edition, reaffirmed 2009; 

incorporated by reference at 

§250.1202(a)(2), (a)(3), and (g); 

(85) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 4—Calculation of 

Base Prover Volumes by the 

Waterdraw Method, First Edition, reaffirmed 2009; incorporated by reference at §250.1202(a)(2), (a)(3), (f)(1), 

and (g); 

(86) API Manual of Petroleum Measurement Standards (MPMS) Chapter 

21—Flow Measurement Using Electronic Metering Systems, Section 2— 

Electronic Liquid Volume Measurement Using Positive Displacement and 

Turbine Meters; First Edition, June 

1998; incorporated by reference at 

§250.1202(a)(2); 

(87) API Manual of Petroleum Measurement Standards Chapter 21—Flow 

Measurement Using Electronic Metering Systems, Addendum to Section 2— 

Flow Measurement Using Electronic 

Metering Systems, Inferred Mass; First 

Edition, reaffirmed February 2006; incorporated by reference at 

§250.1202(a)(2); 

(88) API RP 86, API Recommended 

Practice for Measurement of Multiphase Flow; First Edition, September 

2005; incorporated by reference at 

§250.1202(a)(2), (a)(3), and §250.1203(b)(2). 

(i) American Society for Testing and 

Materials (ASTM), ASTM Standards, 

100 Bar Harbor Drive, P. O. Box C700, 

West Conshohocken, PA 19428–2959; 

http://www.astm.org; phone: 610–832–9500: 

(1) ASTM Standard C 33–07, approved 

December 15, 2007, Standard Specification for Concrete Aggregates; incorporated by reference at §250.901; 

(2) ASTM Standard C 94/C 94M–07, approved January 1, 2007, Standard Specification for Ready-Mixed Concrete; incorporated by reference at §250.901; 

(3) ASTM Standard C 150–07, approved 

May 1, 2007, Standard Specification for 

Portland Cement; incorporated by reference at §250.901; 

(4) ASTM Standard C 330–05, approved 

December 15, 2005, Standard Specification for Lightweight Aggregates for 

Structural Concrete; incorporated by 

reference at §250.901; 

(5) ASTM Standard C 595–08, approved 

January 1, 2008, Standard Specification 

for Blended Hydraulic Cements; incorporated by reference at §250.901; 

(j) American Welding Society (AWS), 

AWS Codes, 550 NW, LeJeune Road, 

Miami, FL 33126; http://www.aws.org; 

phone: 800–443–9353: 

(1) AWS D1.1:2000, Structural Welding 

Code—Steel, 17th Edition, October 18, 

1999; incorporated by reference at 

§250.901; 

(2) AWS D1.4–98, Structural Welding 

Code—Reinforcing Steel, 1998 Edition; 

incorporated by reference at §250.901; 

(3) AWS D3.6M:1999, Specification for 

Underwater Welding (1999); incorporated by reference at §250.901. 

(k) National Association of Corrosion 

Engineers (NACE), NACE Standards, 

1440 South Creek Drive, Houston, TX 

77084; http://www.nace.org; phone: 281– 

228–6200: 

(1) NACE Standard MR0175–2003, 

Standard Material Requirements, Metals for Sulfide Stress Cracking and 

Stress Corrosion Cracking Resistance 

in Sour Oilfield Environments, Revised 

January 17, 2003; incorporated by reference at §§250.901 and 250.490; 


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Safety & Environmental Enforcement, Interior § 250.199 

(2) NACE Standard RP0176–2003, 

Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore 

Structures Associated with Petroleum 

Production; incorporated by reference 

at §250.901. 

(l) American Gas Association (AGA 

Reports), 400 North Capitol Street, 

NW., Suite 450, Washington, DC 20001, 

http://www.aga.org; phone: 202–824–7000; 

(1) AGA Report No. 7—Measurement 

of Natural Gas by Turbine Meters; Revised February 2006; incorporated by 

reference at §250.1203(b)(2); 

(2) AGA Report No. 9—Measurement 

of Gas by Multipath Ultrasonic Meters; 

Second Edition, April 2007; incorporated by reference at §250.1203(b)(2); 

(3) AGA Report No. 10—Speed of 

Sound in Natural Gas and Other Related Hydrocarbon Gases; Copyright 

2003; incorporated by reference at 

§250.1203(b)(2). 

(m) International Organization for 

Standardization (ISO), 1, ch. De la VoiCreuse, Case postale 56, CH–1211, Geneva 20, Switzerland; www.iso.org; phone: 

41–22–749–01–11. 

(1) ISO/IEC (International Electrotechnical Commission) 17011, Conformity assessment—General requirements for accreditation bodies accrediting conformity assessment bodies, 

First edition 2004–09–01; Corrected 

version 2005–02–15; incorporated by reference at §§250.1900, 250.1903, 250.1904, 

and 250.1922. 

(2) [Reserved] 

(n) Center for Offshore Safety (COS), 

1990 Post Oak Blvd., Suite 1370, Houston, TX 77056; www.centerforoff

shoresafety.org; phone: 832–495–4925. 

(1) COS Safety Publication COS–2–01, 

Qualification and Competence Requirements for Audit Teams and Auditors 

Performing Third-party SEMS Audits 

of Deepwater Operations, First Edition, 

Effective Date October 2012; incorporated by reference at §§250.1900, 

250.1903, 250.1904, and 250.1921. 

(2) COS Safety Publication COS–2–03, 

Requirements for Third-party SEMS 

Auditing and Certification of Deepwater Operations, First Edition, Effective Date October 2012; incorporated by 

reference at §§250.1900, 250.1903, 250.1904, 

and 250.1920. 

(3) COS Safety Publication COS–2–04, 

Requirements for Accreditation of 

Audit Service Providers Performing 

SEMS Audits and Certification of 

Deepwater Operations, First Edition, 

Effective Date October 2012; incorporated by reference at §§250.1900, 

250.1903, 250.1904, and 250.1922. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 18921, Mar. 29, 2012; 77 FR 50891, Aug. 22, 

2012; 78 FR 20440, Apr. 5, 2013] 

§ 250.199 Paperwork Reduction Act 

statements—information collection. 

(a) OMB has approved the information collection requirements in part 250 

under 44 U.S.C. 3501 et seq. The table in 

paragraph (e) of this section lists the 

subpart in the rule requiring the information and its title, provides the OMB 

control number, and summarizes the 

reasons for collecting the information 

and how BSEE uses the information. 

The associated BSEE forms required by 

this part are listed at the end of this 

table with the relevant information. 

(b) Respondents are OCS oil, gas, and 

sulphur lessees and operators. The requirement to respond to the information collections in this part is mandated under the Act (43 U.S.C. 1331 et 

seq.) and the Act’s Amendments of 1978 

(43 U.S.C. 1801 et seq.). Some responses 

are also required to obtain or retain a 

benefit or may be voluntary. Proprietary information will be protected 

under §250.197, Data and information to 

be made available to the public or for 

limited inspection; parts 30 CFR Parts 

251, 252; and the Freedom of Information Act (5 U.S.C. 552) and its implementing regulations at 43 CFR part 2. 

(c) The Paperwork Reduction Act of 

1995 requires us to inform the public 

that an agency may not conduct or 

sponsor, and you are not required to respond to, a collection of information 

unless it displays a currently valid 

OMB control number. 

(d) Send comments regarding any aspect of the collections of information 

under this part, including suggestions 

for reducing the burden, to the Information Collection Clearance Officer, 

Bureau of Safety and Environmental 

Enforcement, 381 Elden Street, Herndon, VA 20170. 

(e) BSEE is collecting this information for the reasons given in the following table: 


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§ 250.199 30 CFR Ch. II (7–1–13 Edition) 

30 CFR subpart, title and/or BSEE Form 

(OMB Control No.) Reasons for collecting information and how used 

(1) Subpart A, General (1010–0114), including Forms BSEE– 

0132, Evacuation Statistics; BSEE–0143, Facility/Equipment 

Damage Report; BSEE–1832, Notification of Incidents of 

Noncompliance.

To inform BSEE of actions taken to comply with general operational requirements on the OCS. To ensure that operations 

on the OCS meet statutory and regulatory requirements, are 

safe and protect the environment, and result in diligent exploration, development, and production on OCS leases. To 

support the unproved and proved reserve estimation, resource assessment, and fair market value determinations. 

To allow BSEE to rapidly assess damage and project any 

disruption of oil and gas production from the OCS after a 

major natural occurrence. 

(2) Subpart B, Exploration and Development and Production 

Plans (1010–0151).

To inform BSEE, States, and the public of planned exploration, 

development, and production operations on the OCS. To ensure that operations on the OCS are planned to comply with 

statutory and regulatory requirements, will be safe and protect the human, marine, and coastal environment, and will 

result in diligent exploration, development, and production of 

leases. 

(3) Subpart C, Pollution Prevention and Control (1010–0057) ... To inform BSEE of measures to be taken to prevent water pollution. To ensure that appropriate measures are taken to 

prevent water pollution. 

(4) Subpart D, Oil and Gas and Drilling Operations (1010– 

0141), including Forms BSEE–0123, Application for Permit to 

Drill; BSEE–0123S, Supplemental APD Information Sheet; 

BSEE–0124, Application for Permit to Modify; BSEE–0125, 

End of Operations Report; BSEE–0133, Well Activity Report; 

BSEE–0133S, Open Hole Data Report; and BSEE–144, Rig 

Movement Notification Report.

To inform BSEE of the equipment and procedures to be used 

in drilling operations on the OCS. To ensure that drilling operations are safe and protect the human, marine, and coastal environment. 

(5) Subpart E, Oil and Gas Well-Completion Operations (1010– 

0067).

To inform BSEE of the equipment and procedures to be used 

in well-completion operations on the OCS. To ensure that 

well-completion operations are safe and protect the human, 

marine, and coastal environment. 

(6) Subpart F, Oil and Gas Well Workover Operations (1010– 

0043).

To inform BSEE of the equipment and procedures to be used 

during well-workover operations on the OCS. To ensure that 

well-workover operations are safe and protect the human, 

marine, and coastal environment. 

(7) Subpart H, Oil and Gas Production Safety Systems (1010– 

0059).

To inform BSEE of the equipment and procedures to be used 

during production operations on the OCS. To ensure that 

production operations are safe and protect the human, marine, and coastal environment. 

(8) Subpart I, Platforms and Structures (1010–0149) ................. To provide BSEE with information regarding the design, fabrication, and installation of platforms on the OCS. To ensure 

the structural integrity of platforms installed on the OCS. 

(9) Subpart J, Pipelines and Pipeline Rights-of-Way (1010– 

0050), including Form BSEE–0149, Assignment of Federal 

OCS Pipeline Right-of-Way Grant.

To provide BSEE with information regarding the design, installation, and operation of pipelines on the OCS. To ensure 

that pipeline operations are safe and protect the human, marine, and coastal environment. 

(10) Subpart K, Oil and Gas Production Rates (1010–0041), including Forms BSEE–0126, Well Potential Test Report and 

BSEE–0128, Semiannual Well Test Report.

To inform BSEE of production rates for hydrocarbons produced 

on the OCS. To ensure economic maximization of ultimate 

hydrocarbon recovery 

(11) Subpart L, Oil and Gas Production Measurement, Surface 

Commingling, and Security (1010–0051).

To inform BSEE of the measurement of production, commingling of hydrocarbons, and site security plans. To ensure 

that produced hydrocarbons are measured and commingled 

to provide for accurate royalty payments and security is 

maintained. 

(12) Subpart M, Unitization (1010–0068) .................................... To inform BSEE of the unitization of leases. To ensure that 

unitization prevents waste, conserves natural resources, and 

protects correlative rights. 

(13) Subpart N, Remedies and Penalties ................................... The requirements in subpart N are exempt from the Paperwork 

Reduction Act of 1995 according to 5 CFR 1320.4. 

(14) Subpart O, Well Control and Production Safety Training 

(1010–0128).

To inform BSEE of training program curricula, course schedules, and attendance. To ensure that training programs are 

technically accurate and sufficient to meet safety and environmental requirements, and that workers are properly 

trained to operate on the OCS. 

(15) Subpart P, Sulphur Operations (1010–0086) ...................... To inform BSEE of sulphur exploration and development operations on the OCS. To ensure that OCS sulphur operations 

are safe; protect the human, marine, and coastal environment; and will result in diligent exploration, development, 

and production of sulphur leases. 


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Safety & Environmental Enforcement, Interior § 250.200 

30 CFR subpart, title and/or BSEE Form 

(OMB Control No.) Reasons for collecting information and how used 

(16) Subpart Q, Decommissioning Activities (1010–0142) ......... To determine that decommissioning activities comply with regulatory requirements and approvals. To ensure that site 

clearance and platform or pipeline removal are properly performed to protect marine life and the environment and do not 

conflict with other users of the OCS. 

(17) Subpart S, Safety and Environmental Management Systems (1010–0186), including Form BSEE–0131, Performance Measures Data.

The SEMS program will describe management commitment to 

safety and the environment, as well as policies and procedures to assure safety and environmental protection while 

conducting OCS operations (including those operations conducted by contractor and subcontractor personnel). The information collected is the form to gather the raw Performance Measures Data relating to risk and number of accidents, injuries, and oil spills during OCS activities. 

Subpart B—Plans and Information 

GENERAL INFORMATION

§ 250.200 Definitions. 

Acronyms and terms used in this subpart have the following meanings: 

(a) Acronyms used frequently in this 

subpart are listed alphabetically below: 

BOEM means Bureau of Ocean Energy Management of the Department of 

the Interior. 

BSEE means Bureau of Safety and 

Environmental Enforcement of the Department of the Interior. 

CID means Conservation Information 

Document. 

CZMA means Coastal Zone Management Act. 

DOCD means Development Operations Coordination Document. 

DPP means Development and Production Plan. 

DWOP means Deepwater Operations 

Plan. 

EIA means Environmental Impact 

Analysis. 

EP means Exploration Plan. 

NPDES means National Pollutant 

Discharge Elimination System. 

NTL means Notice to Lessees and Operators. 

OCS means Outer Continental Shelf. 

(b) Terms used in this subpart are 

listed alphabetically below: 

Amendment means a change you make 

to an EP, DPP, or DOCD that is pending before BOEM for a decision (see 30 

CFR 550.232(d) and 550.267(d)). 

Modification means a change required 

by the Regional Supervisor to an EP, 

DPP, or DOCD (see 30 CFR 550.233(b)(2) 

and 550.270(b)(2)) that is pending before 

BOEM for a decision because the OCS 

plan is inconsistent with applicable requirements. 

New or unusual technology means 

equipment or procedures that: 

(1) Have not been used previously or 

extensively in a BSEE OCS Region; 

(2) Have not been used previously 

under the anticipated operating conditions; or 

(3) Have operating characteristics 

that are outside the performance parameters established by this part. 

Non-conventional production or completion technology includes, but is not limited to, floating production systems, 

tension leg platforms, spars, floating 

production, storage, and offloading systems, guyed towers, compliant towers, 

subsea manifolds, and other subsea production components that rely on a remote site or host facility for utility 

and well control services. 

Offshore vehicle means a vehicle that 

is capable of being driven on ice. 

Resubmitted OCS plan means an EP, 

DPP, or DOCD that contains changes 

you make to an OCS plan that BOEM 

has disapproved (see 30 CFR 550.234(b), 

550.272(a), and 550.273(b)). 

Revised OCS plan means an EP, DPP, 

or DOCD that proposes changes to an 

approved OCS plan, such as those in 

the location of a well or platform, type 

of drilling unit, or location of the onshore support base (see 30 CFR 

550.283(a)). 

Supplemental OCS plan means an EP, 

DPP, or DOCD that proposes the addition to an approved OCS plan of an activity that requires approval of an application or permit (see 30 CFR 

550.283(b)). 


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§ 250.201 30 CFR Ch. II (7–1–13 Edition) 

§ 250.201 What plans and information 

must I submit before I conduct any 

activities on my lease or unit? 

(a) Plans and documents. Before you 

conduct the activities on your lease or 

unit listed in the following table, you 

must submit, and BSEE must approve, 

the listed plans and documents. Your 

plans and documents may cover one or 

more leases or units. 

You must submit a(n) . . . Before you . . . 

(1) [Reserved] 

(2) [Reserved] 

(3) [Reserved] 

(4) Deepwater Operations Plan 

(DWOP), 

Conduct post-drilling installation 

activities in any 

water depth associated with a 

development 

project that will 

involve the use 

of a non-conventional production 

or completion 

technology. 

(5) [Reserved] 

(6) [Reserved] 

(b) Submitting additional information. 

On a case-by-case basis, the Regional 

Supervisor may require you to submit 

additional information if the Regional 

Supervisor determines that it is necessary to evaluate your proposed plan 

or document. 

(c) Limiting information. The Regional 

Director may limit the amount of information or analyses that you otherwise must provide in your proposed 

plan or document under this subpart 

when: 

(1) Sufficient applicable information 

or analysis is readily available to 

BSEE; 

(2) Other coastal or marine resources 

are not present or affected; 

(3) Other factors such as technological advances affect information 

needs; or 

(4) Information is not necessary or 

required for a State to determine consistency with their CZMA Plan. 

(d) Referencing. In preparing your 

proposed plan or document, you may 

reference information and data discussed in other plans or documents you 

previously submitted or that are otherwise readily available to BSEE. 

§§ 250.202–250.203 [Reserved] 

§ 250.204 How must I protect the rights 

of the Federal government? 

(a) To protect the rights of the Federal government, you must either: 

(1) Drill and produce the wells that 

the Regional Supervisor determines are 

necessary to protect the Federal government from loss due to production on 

other leases or units or from adjacent 

lands under the jurisdiction of other 

entities (e.g., State and foreign governments); or 

(2) Pay a sum that the Regional Supervisor determines as adequate to 

compensate the Federal government 

for your failure to drill and produce 

any well. 

(b) Payment under paragraph (a)(2) of 

this section may constitute production 

in paying quantities for the purpose of 

extending the lease term. 

(c) You must complete and produce 

any penetrated hydrocarbon-bearing 

zone that the Regional Supervisor determines is necessary to conform to 

sound conservation practices. 

§ 250.205 Are there special requirements if my well affects an adjacent 

property? 

For wells that could intersect or 

drain an adjacent property, the Regional Supervisor may require special 

measures to protect the rights of the 

Federal government and objecting lessees or operators of adjacent leases or 

units. 

POST-APPROVAL REQUIREMENTS FOR THE

EP, DPP, AND DOCD 

§ 250.282 Do I have to conduct post-approval monitoring? 

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 BSEE upon request. 

The Regional Supervisor may require 

you to: 

(a) Monitoring plans. Submit monitoring plans for approval before you 

begin work; and 

(b) Monitoring reports. Prepare and 

submit reports that summarize and 

analyze data and information obtained 


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Safety & Environmental Enforcement, Interior § 250.292 

or derived from your monitoring programs. The Regional Supervisor will 

specify requirements for preparing and 

submitting these reports. 

DEEPWATER OPERATIONS PLAN (DWOP) 

§ 250.286 What is a DWOP? 

(a) A DWOP is a plan that provides 

sufficient information for BSEE to review a deepwater development project, 

and any other project that uses nonconventional production or completion 

technology, from a total system approach. The DWOP does not replace, 

but supplements other submittals required by the regulations such as 

BOEM Exploration Plans, Development 

and Production Plans, and Development Operations Coordination Documents. BSEE 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? 

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 

BSEE 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? 

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? 

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? 

You may not complete any production well or install the subsea wellhead 

and well safety control system (often 

called the tree) before BSEE has approved the Conceptual Plan. 

§ 250.291 When and how must I submit 

the DWOP? 

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? 

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; 


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§ 250.293 30 CFR Ch. II (7–1–13 Edition) 

(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; 

(o) A list of any alternate compliance 

procedures or departures for which you 

anticipate requesting approval; and 

(p) Payment of the service fee listed 

in §250.125. 

§ 250.293 What operations require approval of the DWOP? 

You may not begin production until 

BSEE approves your DWOP. 

§ 250.294 May I combine the Conceptual Plan and the DWOP? 

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? 

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. 

Subpart C—Pollution Prevention 

and Control 

§ 250.300 Pollution prevention. 

(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 Manager 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 Manager. 

(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. 


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Safety & Environmental Enforcement, Interior § 250.400 

(b)(1) The District Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager 

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 Manager. 

(2) Approval of the method of disposal of drill cuttings, sand, and other 

well solids shall be obtained from the 

District Manager. 

(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 Manager. 

§ 250.301 Inspection of facilities. 

Drilling and production facilities 

shall be inspected daily or at intervals 

approved or prescribed by the District 

Manager 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. 

Subpart D—Oil and Gas Drilling 

Operations 

GENERAL REQUIREMENTS

§ 250.400 Who is subject to the requirements of this subpart? 

The requirements of this subpart 

apply to lessees, operating rights owners, operators, and their contractors 

and subcontractors. 


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§ 250.401 30 CFR Ch. II (7–1–13 Edition) 

§ 250.401 What must I do to keep wells 

under control? 

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. 

§ 250.402 When and how must I secure 

a well? 

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 wellcontrol equipment. 

(b) For floating drilling operations, 

the District Manager 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. 

§ 250.403 What drilling unit movements must I report? 

(a) You must report the movement of 

all drilling units on and off drilling locations to the District Manager. This 

includes both MODU and platform rigs. 

You must inform the District Manager 

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 

Manager 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 BSEE–0144, Rig Movement Notification Report. 

§ 250.404 What are the requirements 

for the crown block? 

You must have a crown block safety 

device that prevents the traveling 

block from striking the crown block. 

You must check the device for proper 

operation at least once per week and 

after each drill-line slipping operation 

and record the results of this operational check in the driller’s report. 

§ 250.405 What are the safety requirements for diesel engines used on a 

drilling rig? 

You must equip each diesel engine 

with an air 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; 


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Safety & Environmental Enforcement, Interior § 250.411 

(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. 

§ 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? 

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 

below the surface and at the wellhead 

when: 

(1) You move a drilling rig or related 

equipment on and off a platform. This 

includes rigging up and rigging down 

activities within 500 feet of the affected 

platform; 

(2) You move or skid a drilling unit 

between wells on a platform; 

(3) A mobile offshore drilling unit 

(MODU) moves within 500 feet of a platform. You may resume production once 

the MODU is in place, secured, and 

ready to begin drilling operations. 

§ 250.407 What tests must I conduct to 

determine reservoir characteristics? 

You must determine the presence, 

quantity, quality, and reservoir characteristics of oil, gas, sulphur, and 

water in the formations penetrated by 

logging, formation sampling, or well 

testing. 

§ 250.408 May I use alternative procedures or equipment during drilling 

operations? 

You may use alternative procedures 

or equipment during drilling operations after receiving approval from 

the District Manager. You must identify and discuss your proposed alternative procedures or equipment in your 

Application for Permit to Drill (APD) 

(Form BSEE–0123) (see §250.414(h)). 

Procedures for obtaining approval are 

described in §250.141 of this part. 

§ 250.409 May I obtain departures from 

these drilling requirements? 

The District Manager may approve 

departures from the drilling requirements specified in this subpart. You 

may apply for a departure from drilling 

requirements by writing to the District 

Manager. You should identify and discuss the departure you are requesting 

in your APD (see §250.414(h)). 

APPLYING FOR A PERMIT TO DRILL

§ 250.410 How do I obtain approval to 

drill a well? 

You must obtain written approval 

from the District Manager before you 

begin drilling any well or before you 

sidetrack, bypass, or deepen a well. To 

obtain approval, you must: 

(a) Submit the information required 

by §§250.411 through 250.418; 

(b) Include the well in your approved 

Exploration Plan (EP), Development 

and Production Plan (DPP), or Development Operations Coordination Document (DOCD); 

(c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30 CFR part 553; 

and 

(d) Submit the following to the District Manager: 

(1) An original and two complete copies of Form BSEE–0123, Application for 

Permit to Drill (APD), and Form 

BSEE–0123S, Supplemental APD Information Sheet; 

(2) A separate public information 

copy of forms BSEE–0123 and BSEE– 

0123S that meets the requirements of 

§250.186; and 

(3) Payment of the service fee listed 

in §250.125. 

§ 250.411 What information must I submit with my application? 

In addition to forms BSEE–0123 and 

BSEE–0123S, you must include the information described in the following 

table. 


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§ 250.412 30 CFR Ch. II (7–1–13 Edition) 

Information that you must 

include with an APD 

Where to find a 

description 

(a) Plat that shows locations of the proposed well.§ 250.412 

(b) Design criteria used for the proposed 

well.

§ 250.413 

(c) Drilling prognosis ................................. § 250.414 

(d) Casing and cementing programs ........ § 250.415 

(e) Diverter and BOP systems descriptions.§ 250.416 

(f) Requirements for using an MODU ...... § 250.417 

(g) Additional information .......................... § 250.418 

§ 250.412 What requirements must the 

location plat meet? 

The location plat must: 

(a) Have a scale of 1:24,000 (1 inch = 

2,000 feet); 

(b) Show the surface and subsurface 

locations of the proposed well and all 

the wells in the vicinity; 

(c) Show the surface and subsurface 

locations of the proposed well in feet or 

meters from the block line; 

(d) Contain the longitude and latitude coordinates, and either Universal 

Transverse Mercator grid-system coordinates or state plane coordinates in 

the Lambert or Transverse Mercator 

Projection system for the surface and 

subsurface locations of the proposed 

well; and 

(e) State the units and geodetic 

datum (including whether the datum is 

North American Datum 27 or 83) for 

these coordinates. If the datum was 

converted, you must state the method 

used for this conversion, since the various methods may produce different 

values. 

§ 250.413 What must my description of 

well drilling design criteria address? 

Your description of well drilling design criteria must address: 

(a) Pore pressures; 

(b) Formation fracture gradients, adjusted for water depth; 

(c) Potential lost circulation zones; 

(d) Drilling fluid weights; 

(e) Casing setting depths; 

(f) Maximum anticipated surface 

pressures. For this section, maximum 

anticipated surface pressures are the 

pressures that you reasonably expect 

to be exerted upon a casing string and 

its related wellhead equipment. In calculating maximum anticipated surface 

pressures, you must consider: drilling, 

completion, and producing conditions; 

drilling fluid densities to be used below 

various casing strings; fracture gradients of the exposed formations; casing setting depths; total well depth; 

formation fluid types; safety margins; 

and other pertinent conditions. You 

must include the calculations used to 

determine the pressures for the drilling 

and the completion phases, including 

the anticipated surface pressure used 

for designing the production string; 

(g) A single plot containing estimated pore pressures, formation fracture gradients, proposed drilling fluid 

weights, and casing setting depths in 

true vertical measurements; 

(h) A summary report of the shallow 

hazards site survey that describes the 

geological and manmade conditions if 

not previously submitted; and 

(i) Permafrost zones, if applicable. 

§ 250.414 What must my drilling prognosis include? 

Your drilling prognosis must include 

a brief description of the procedures 

you will follow in drilling the well. 

This prognosis includes but is not limited to the following: 

(a) Projected plans for coring at specified depths; 

(b) Projected plans for logging; 

(c) Planned safe drilling margin between proposed drilling fluid weights 

and estimated pore pressures. This safe 

drilling margin may be shown on the 

plot required by §250.413(g); 

(d) Estimated depths to the top of 

significant marker formations; 

(e) Estimated depths to significant 

porous and permeable zones containing 

fresh water, oil, gas, or abnormally 

pressured formation fluids; 

(f) Estimated depths to major faults; 

(g) Estimated depths of permafrost, if 

applicable; 

(h) A list and description of all requests for using alternative procedures 

or departures from the requirements of 

this subpart in one place in the APD. 

You must explain how the alternative 

procedures afford an equal or greater 

degree of protection, safety, or performance, or why you need the departures; and 

(i) Projected plans for well testing 

(refer to §250.460 for safety requirements). 


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Safety & Environmental Enforcement, Interior § 250.416 

§ 250.415 What must my casing and cementing programs include? 

Your casing and cementing programs 

must include: 

(a) Hole sizes and casing sizes, including: weights; grades; collapse, and 

burst values; types of connection; and 

setting depths (measured and true 

vertical depth (TVD)); 

(b) Casing design safety factors for 

tension, collapse, and burst with the 

assumptions made to arrive at these 

values; 

(c) Type and amount of cement (in 

cubic feet) planned for each casing 

string; 

(d) In areas containing permafrost, 

setting depths for conductor and surface casing based on the anticipated 

depth of the permafrost. Your program 

must provide protection from thaw 

subsidence and freezeback effect, proper anchorage, and well control; 

(e) A statement of how you evaluated 

the best practices included in API RP 

65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep 

Water Wells (as incorporated by reference in §250.198), if you drill a well in 

water depths greater than 500 feet and 

are in either of the following two areas: 

(1) An ‘‘area with an unknown shallow water flow potential’’ is a zone or 

geologic formation where neither the 

presence nor absence of potential for a 

shallow water flow has been confirmed. 

(2) An ‘‘area known to contain a shallow water flow hazard’’ is a zone or 

geologic formation for which drilling 

has confirmed the presence of shallow 

water flow; and 

(f) A written description of how you 

evaluated the best practices included 

in API Standard 65—Part 2, Isolating 

Potential Flow Zones During Well Construction, Second Edition (as incorporated by reference in §250.198). Your 

written description must identify the 

mechanical barriers and cementing 

practices you will use for each casing 

string (reference API Standard 65— 

Part 2, Sections 4 and 5). 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50891, Aug. 22, 2012] 

§ 250.416 What must I include in the 

diverter and BOP descriptions? 

You must include in the diverter and 

BOP descriptions: 

(a) A description of the diverter system and its operating procedures; 

(b) A schematic drawing of the diverter system (plan and elevation 

views) that shows: 

(1) The size of the annular BOP installed in the diverter housing; 

(2) Spool outlet internal diameter(s); 

(3) Diverter-line lengths and diameters; burst strengths and radius of curvature at each turn; and 

(4) Valve type, size, working pressure 

rating, and location; 

(c) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(d) A schematic drawing of the BOP 

system that shows the inside diameter 

of the BOP stack, number and type of 

preventers, all control systems and 

pods, location of choke and kill lines, 

and associated valves; 

(e) Independent third-party 

verification and supporting documentation that show the blind-shear 

rams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole 

under maximum anticipated surface 

pressure. The documentation must include actual shearing and subsequent 

pressure integrity test results for the 

most rigid pipe to be used and calculations of shearing capacity of all pipe to 

be used in the well, including correction for MASP; 

(f) When you use a subsea BOP stack 

or surface BOP stack on a floating facility, independent third-party 

verification that shows: 

(1) The BOP stack is designed for the 

specific equipment on the rig and for 

the specific well design; 

(2) The BOP stack has not been compromised or damaged from previous 

service; 

(3) The BOP stack will operate in the 

conditions in which it will be used; and 

(g) The qualifications of the independent third-party referenced in paragraphs (e) and (f) of this section: 

(1) The independent third-party in 

this section must be a technical classification society, or a licensed professional engineering firm, or a registered 

professional engineer capable of providing the verifications required under 

this part. 


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§ 250.417 30 CFR Ch. II (7–1–13 Edition) 

(2) You must: 

(i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm you are using or its employees hold appropriate licenses to 

perform the verification in the appropriate jurisdiction, and evidence to 

demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the required verifications. 

(ii) Ensure that an official representative of BSEE will have access to the 

location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must notify the BSEE District Manager at 

least 72 hours in advance. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50891, Aug. 22, 2012] 

§ 250.417 What must I provide if I plan 

to use a mobile offshore drilling 

unit (MODU)? 

If you plan to use a MODU, you must 

provide: 

(a) Fitness requirements. You must 

provide information and data to demonstrate the drilling unit’s capability 

to perform at the proposed drilling location. This information must include 

the maximum environmental and operational conditions that the unit is designed to withstand, including the minimum air gap necessary for both hurricane and non-hurricane seasons. If sufficient environmental information and 

data are not available at the time you 

submit your APD, the District Manager may approve your APD but require you to collect and report this information during operations. Under 

this circumstance, the District Manager has the right to revoke the approval of the APD if information collected during operations show that the 

drilling unit is not capable of performing at the proposed location. 

(b) Foundation requirements. You must 

provide information to show that sitespecific soil and oceanographic conditions are capable of supporting the proposed drilling unit. If you provided sufficient site-specific information in 

your EP, DPP, or DOCD submitted to 

BOEM, you may reference that information. The District Manager may require you to conduct additional surveys and soil borings before approving 

the APD if additional information is 

needed to make a determination that 

the conditions are capable of supporting the drilling unit. 

(c) Frontier areas. (1) If the design of 

the drilling unit you plan to use in a 

frontier area is unique or has not been 

proven for use in the proposed environment, the District Manager may require you to submit a third-party review of the unit’s design. If required, 

you must obtain the third-party review 

according to §§250.915 through 250.918. 

You may submit this information before submitting an APD. 

(2) If you plan to drill in a frontier 

area, you must have a contingency 

plan that addresses design and operating limitations of the drilling unit. 

Your plan must identify the actions 

necessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of drilling or 

rig operations to remedy various operational or environmental situations 

(e.g., vessel motion, riser offset, anchor 

tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt 

or lateral movement, resupply capability). 

(d) U.S. Coast Guard (USCG) documentation. You must provide the current Certificate of Inspection or Letter 

of Compliance from the USCG. You 

must also provide current documentation of any operational limitations imposed by an appropriate classification 

society. 

(e) Floating drilling unit. If you use a 

floating drilling unit, you must indicate that you have a contingency plan 

for moving off location in an emergency situation. 

(f) Inspection of unit. The drilling unit 

must be available for inspection by the 

District Manager before commencing 

operations. 

(g) Once the District Manager has approved a MODU for use, you do not 

need to re-submit the information required by this section for another APD 

to use the same MODU unless changes 

in equipment affect its rated capacity 

to operate in the District. 


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Safety & Environmental Enforcement, Interior § 250.420 

§ 250.418 What additional information 

must I submit with my APD? 

You must include the following with 

the APD: 

(a) Rated capacities of the drilling 

rig and major drilling equipment, if not 

already on file with the appropriate 

District office; 

(b) A drilling fluids program that includes the minimum quantities of drilling fluids and drilling fluid materials, 

including weight materials, to be kept 

at the site; 

(c) A proposed directional plot if the 

well is to be directionally drilled; 

(d) A Hydrogen Sulfide Contingency 

Plan (see §250.490), if applicable, and 

not previously submitted; 

(e) A welding plan (see §§250.109 to 

250.113) if not previously submitted; 

(f) In areas subject to subfreezing 

conditions, evidence that the drilling 

equipment, BOP systems and components, diverter systems, and other associated equipment and materials are 

suitable for operating under such conditions; 

(g) A request for approval if you plan 

to wash out below the mudline or displace some cement to facilitate casing 

removal upon well abandonment; 

(h) Certification of your casing and 

cementing program as required in 

§250.420(a)(6); 

(i) Descriptions of qualifications required by §250.416(g) of the independent 

third-party; and 

(j) Such other information as the District Manager may require. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50892, Aug. 22, 2012] 

CASING AND CEMENTING REQUIREMENTS

§ 250.420 What well casing and cementing requirements must I meet? 

You must case and cement all wells. 

Your casing and cementing programs 

must meet the requirements of this 

section and of §§250.421 through 250.428. 

(a) Casing and cementing program requirements. Your casing and cementing 

programs must: 

(1) Properly control formation pressures and fluids; 

(2) Prevent the direct or indirect release of fluids from any stratum 

through the wellbore into offshore 

waters; 

(3) Prevent communication between 

separate hydrocarbon-bearing strata; 

(4) Protect freshwater aquifers from 

contamination; 

(5) Support unconsolidated sediments; and 

(6)(i) Include a certification signed by 

a registered professional engineer that 

the casing and cementing design is appropriate for the purpose for which it is 

intended under expected wellbore conditions, and is sufficient to satisfy the 

tests and requirements of this section 

and §250.423. Submit this certification 

with your APD (Form BSEE–0123). 

(ii) You must have the registered professional engineer involved in the casing and cementing design process. 

(iii) The registered professional engineer must be registered in a state of 

the United States and have sufficient 

expertise and experience to perform 

the certification. 

(b) Casing requirements. (1) You must 

design casing (including liners) to 

withstand the anticipated stresses imposed by tensile, compressive, and 

buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. 

(2) The casing design must include 

safety measures that ensure well control during drilling and safe operations 

during the life of the well. 

(3) On all wells that use subsea BOP 

stacks, you must include two independent barriers, including one mechanical barrier, in each annular flow 

path (examples of barriers include, but 

are not limited to, primary cement job 

and seal assembly). For the final casing 

string (or liner if it is your final 

string), you must install one mechanical barrier in addition to cement to 

prevent flow in the event of a failure in 

the cement. A dual float valve, by 

itself, is not considered a mechanical 

barrier. These barriers cannot be modified prior to or during completion or 

abandonment operations. The BSEE 

District Manager may approve alternative options under §250.141. You must 

submit documentation of this installation to BSEE in the End-of-Operations 

Report (Form BSEE–0125). 

(c) Cementing requirements. You must 

design and conduct your cementing 

jobs so that cement composition, 

placement techniques, and waiting 


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§ 250.421 30 CFR Ch. II (7–1–13 Edition) 

times ensure that the cement placed 

behind the bottom 500 feet of casing attains a minimum compressive strength 

of 500 psi before drilling out of the casing or before commencing completion 

operations. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50892, Aug. 22, 2012] 

§ 250.421 What are the casing and cementing requirements by type of 

casing string? 

The table in this section identifies 

specific design, setting, and cementing 

requirements for casing strings and liners. For the purposes of subpart D, the 

casing strings in order of normal installation are as follows: drive or structural, conductor, surface, intermediate, 

and production casings (including liners). The District Manager may approve or prescribe other casing and cementing requirements where appropriate. 

Casing type Casing requirements Cementing requirements 

(a) Drive or Structural ..... Set by driving, jetting, or drilling to the minimum 

depth as approved or prescribed by the District Manager.

If you drilled a portion of this hole, you must use 

enough cement to fill the annular space back 

to the mudline. 

(b) Conductor .................. Design casing and select setting depths based 

on relevant engineering and geologic factors. 

These factors include the presence or absence of hydrocarbons, potential hazards, and 

water depths; 

Set casing immediately before drilling into formations known to contain oil or gas. If you encounter oil or gas or unexpected formation 

pressure before the planned casing point, you 

must set casing immediately.

Use enough cement to fill the calculated annular 

space back to the mudline. 

Verify annular fill by observing cement returns. If 

you cannot observe cement returns, use additional cement to ensure fill-back to the 

mudline. 

For drilling on an artificial island or when using a 

well cellar, you must discuss the cement fill 

level with the District Manager. 

(c) Surface ....................... Design casing and select setting depths based 

on relevant engineering and geologic factors. 

These factors include the presence or absence of hydrocarbons, potential hazards, and 

water depths.

Use enough cement to fill the calculated annular 

space to at least 200 feet inside the conductor 

casing. 

When geologic conditions such as near-surface 

fractures and faulting exist, you must use 

enough cement to fill the calculated annular 

space to the mudline. 

(d) Intermediate ............... Design casing and select setting depth based on 

anticipated or encountered geologic characteristics or wellbore conditions.

Use enough cement to cover and isolate all hydrocarbon-bearing zones and isolate abnormal 

pressure intervals from normal pressure intervals in the well. 

As a minimum, you must cement the annular 

space 500 feet above the casing shoe and 

500 feet above each zone to be isolated. 

(e) Production .................. Design casing and select setting depth based on 

anticipated or encountered geologic characteristics or wellbore conditions.

Use enough cement to cover or isolate all hydrocarbon-bearing zones above the shoe. 

As a minimum, you must cement the annular 

space at least 500 feet above the casing shoe 

and 500 feet above the uppermost hydrocarbon-bearing zone. 

(f) Liners .......................... If you use a liner as conductor or surface casing, 

you must set the top of the liner at least 200 

feet above the previous casing/liner shoe.

If you use a liner as an intermediate string below 

a surface string or production casing below an 

intermediate string, you must set the top of the 

liner at least 100 feet above the previous casing shoe.

Same as cementing requirements for specific 

casing types. For example, a liner used as intermediate casing must be cemented according to the cementing requirements for intermediate casing. 

§ 250.422 When may I resume drilling 

after cementing? 

(a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling after the 

cement has been held under pressure 

for 12 hours. For conductor casing, you 

may resume drilling after the cement 

has been held under pressure for 8 

hours. One acceptable method of holding cement under pressure is to use 

float valves to hold the cement in 

place. 

(b) If you plan to nipple down your 

diverter or BOP stack during the 8- or 


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Safety & Environmental Enforcement, Interior § 250.423 

12-hour waiting time, you must determine, before nippling down, when it 

will be safe to do so. You must base 

your determination on a knowledge of 

formation conditions, cement composition, effects of nippling down, presence 

of potential drilling hazards, well conditions during drilling, cementing, and 

post cementing, as well as past experience. 

§ 250.423 What are the requirements 

for pressure testing casing? 

(a) The table in this section describes 

the minimum test pressures for each 

string of casing. You may not resume 

drilling or other down-hole operations 

until you obtain a satisfactory pressure test. If the pressure declines more 

than 10 percent in a 30-minute test, or 

if there is another indication of a leak, 

you must investigate the cause and receive approval from the appropriate 

BSEE District Manager for the repair 

to resolve the problem ensuring that 

the casing will provide a proper seal. 

The BSEE District Manager may approve or require other casing test pressures. 

Casing type Minimum test 

pressure 

(1) Drive or Structural ............ Not required. 

(2) Conductor ......................... 200 psi. 

(3) Surface, Intermediate, and 

Production.

70 percent of its minimum internal yield. 

(b) You must ensure proper installation of casing in the subsea wellhead or 

liner in the liner hanger. 

(1) You must ensure that the latching 

mechanisms or lock down mechanisms 

are engaged upon installation of each 

casing string. 

(2) If you run a liner that has a latching mechanism or lock down mechanism, you must ensure that the latching mechanisms or lock down mechanisms are engaged upon installation of 

the liner. 

(3) You must perform a pressure test 

on the casing seal assembly to ensure 

proper installation of casing or liner. 

You must perform this test for the intermediate and production casing 

strings or liner. 

(i) You must submit for approval 

with your APD, test procedures and 

criteria for a successful test. 

(ii) You must document all your test 

results and make them available to 

BSEE upon request. 

(c) You must perform a negative 

pressure test on all wells that use a 

subsea BOP stack or wells with 

mudline suspension systems. The BSEE 

District Manager may require you to 

perform additional negative pressure 

tests on other casing strings or liners 

(e.g., intermediate casing string or 

liner) or on wells with a surface BOP 

stack. 

(1) You must perform a negative pressure test on your final casing string or 

liner. 

(2) You must perform a negative test 

prior to unlatching the BOP at any 

point in the well. The negative test 

must be performed on those components, at a minimum, that will be exposed to the negative differential pressure that will occur when the BOP is 

disconnected. 

(3) You must submit for approval 

with your APD, test procedures and 

criteria for a successful test. If any of 

your test procedures or criteria for a 

successful test change, you must submit for approval the changes in a revised APD or APM. 

(4) You must document all your test 

results and make them available to 

BSEE upon request. 

(5) If you have any indication of a 

failed negative pressure test, such as, 

but not limited to pressure buildup or 

observed flow, you must immediately 

investigate the cause. If your investigation confirms that a failure occurred during the negative pressure 

test, you must: 

(i) Correct the problem and immediately contact the appropriate BSEE 

District Manager. 

(ii) Submit a description of the corrective action taken and you must receive approval from the appropriate 

BSEE District Manager for the retest. 

(6) You must have two barriers in 

place, as required in §250.420(b)(3), prior 

to performing the negative pressure 

test. 

(7) You must include documentation 

of the successful negative pressure test 

in the End-of-Operations Report (Form 

BSEE–0125). 

[77 FR 50892, Aug. 22, 2012] 


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§ 250.424 30 CFR Ch. II (7–1–13 Edition) 

§ 250.424 What are the requirements 

for prolonged drilling operations? 

If wellbore operations continue for 

more than 30 days within a casing 

string run to the surface: 

(a) You must stop drilling operations 

as soon as practicable, and evaluate 

the effects of the prolonged operations 

on continued drilling operations and 

the life of the well. At a minimum, you 

must: 

(1) Caliper or pressure test the casing; and 

(2) Report the results of your evaluation to the District Manager and obtain approval of those results before resuming operations. 

(b) If casing integrity has deteriorated to a level below minimum safety 

factors, you must: 

(1) Repair the casing or run another 

casing string; and 

(2) Obtain approval from the District 

Manager before you begin repairs. 

§ 250.425 What are the requirements 

for pressure testing liners? 

(a) You must test each drilling liner 

(and liner-lap) to a pressure at least 

equal to the anticipated pressure to 

which the liner will be subjected during 

the formation pressure-integrity test 

below that liner shoe, or subsequent 

liner shoes if set. The District Manager 

may approve or require other liner test 

pressures. 

(b) You must test each production 

liner (and liner-lap) to a minimum of 

500 psi above the formation fracture 

pressure at the casing shoe into which 

the liner is lapped. 

(c) You may not resume drilling or 

other down-hole operations until you 

obtain a satisfactory pressure test. If 

the pressure declines more than 10 percent in a 30-minute test or if there is 

another indication of a leak, you must 

re-cement, repair the liner, or run additional casing/liner to provide a proper 

seal. 

§ 250.426 What are the recordkeeping 

requirements for casing and liner 

pressure tests? 

You must record the time, date, and 

results of each pressure test in the 

driller’s report maintained under 

standard industry practice. In addition, 

you must record each test on a pressure chart and have your onsite representative sign and date the test as 

being correct. 

§ 250.427 What are the requirements 

for pressure integrity tests? 

You must conduct a pressure integrity test below the surface casing or 

liner and all intermediate casings or 

liners. The District Manager may require you to run a pressure-integrity 

test at the conductor casing shoe if 

warranted by local geologic conditions 

or the planned casing setting depth. 

You must conduct each pressure integrity test after drilling at least 10 feet 

but no more than 50 feet of new hole 

below the casing shoe. You must test 

to either the formation leak-off pressure or to an equivalent drilling fluid 

weight if identified in an approved 

APD. 

(a) You must use the pressure integrity test and related hole-behavior observations, such as pore-pressure test 

results, gas-cut drilling fluid, and well 

kicks to adjust the drilling fluid program and the setting depth of the next 

casing string. You must record all test 

results and hole-behavior observations 

made during the course of drilling related to formation integrity and pore 

pressure in the driller’s report. 

(b) While drilling, you must maintain 

the safe drilling margin identified in 

the approved APD. When you cannot 

maintain this safe margin, you must 

suspend drilling operations and remedy 

the situation. 

§ 250.428 What must I do in certain cementing and casing situations? 

The table in this section describes actions that lessees must take when certain situations occur during casing and 

cementing activities. 

If you encounter the following situation: Then you must . . . 

(a) Have unexpected formation pressures or conditions that 

warrant revising your casing design, 

Submit a revised casing program to the District Manager for 

approval. 


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Safety & Environmental Enforcement, Interior § 250.432 

If you encounter the following situation: Then you must . . . 

(b) Need to increase casing setting depths more than 100 feet 

true vertical depth (TVD) from the approved APD due to conditions encountered during drilling operations, 

Submit those changes to the District Manager for approval. 

(c) Have indication of inadequate cement job (such as, but not 

limited to, lost returns, cement channeling, gas cut mud, or 

failure of equipment), 

(1) Run a temperature survey; (2) Run a cement evaluation 

log; or (3) Use a combination of these techniques. 

(d) Inadequate cement job, Re-cement or take other remedial actions as approved by the 

District Manager. 

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

intervals, 

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

(f) Decide to produce a well that was not originally contemplated for production, Have at least two cemented casing strings (does not include 

liners) in the well. Note: All producing wells must have at 

least two cemented casing strings. 

(g) Want to drill a well without setting conductor casing, Submit geologic data and information to the District Manager 

that demonstrates the absence of shallow hydrocarbons or 

hazards. This information must include logging and drilling 

fluid-monitoring from wells previously drilled within 500 feet 

of the proposed well path down to the next casing point. 

(h) Need to use less than required cement for the surface casing during floating drilling operations to provide protection 

from burst and collapse pressures, 

Submit information to the District Manager that demonstrates 

the use of less cement is necessary. 

(i) Cement across a permafrost zone, Use cement that sets before it freezes and has a low heat of 

hydration. 

(j) Leave the annulus opposite a permafrost zone uncemented, Fill the annulus with a liquid that has a freezing point below the

minimum permafrost temperature and minimizes opposite a 

corrosion. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50892, Aug. 22, 2012] 

DIVERTER SYSTEM REQUIREMENTS

§ 250.430 When must I install a diverter system? 

You must install a diverter system 

before you drill a conductor or surface 

hole. The diverter system consists of a 

diverter sealing element, diverter 

lines, and control systems. You must 

design, install, use, maintain, and test 

the diverter system to ensure proper 

diversion of gases, water, drilling fluid, 

and other materials away from facilities and personnel. 

§ 250.431 What are the diverter design 

and installation requirements? 

You must design and install your diverter system to: 

(a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches for surface 

wellhead configurations and at least 12 

inches for floating drilling operations; 

(b) Use dual diverter lines arranged 

to provide for downwind diversion capability; 

(c) Use at least two diverter control 

stations. One station must be on the 

drilling floor. The other station must 

be in a readily accessible location away 

from the drilling floor; 

(d) Use only remote-controlled valves 

in the diverter lines. All valves in the 

diverter system must be full-opening. 

You may not install manual or butterfly valves in any part of the diverter 

system; 

(e) Minimize the number of turns 

(only one 90-degree turn allowed for 

each line for bottom-founded drilling 

units) in the diverter lines, maximize 

the radius of curvature of turns, and 

target all right angles and sharp turns; 

(f) Anchor and support the entire diverter system to prevent whipping and 

vibration; and 

(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects. 

§ 250.432 How do I obtain a departure 

to diverter design and installation 

requirements? 

The table below describes possible departures from the diverter requirements and the conditions required for 

each departure. To obtain one of these 

departures, you must have discussed 

the departure in your APD and received approval from the District Manager. 


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§ 250.433 30 CFR Ch. II (7–1–13 Edition) 

If you want a departure to: Then you must . . . 

(a) Use flexible hose for diverter lines instead of rigid pipe, Use flexible hose that has integral end couplings. 

(b) Use only one spool outlet for your diverter system, (1) Have branch lines that meet the minimum internal diameter 

requirements; and (2) Provide downwind diversion capability. 

(c) Use a spool with an outlet with an internal diameter of less 

than 10 inches on a surface wellhead, 

Use a spool that has dual outlets with an internal diameter of 

at least 8 inches. 

(d) Use a single diverter line for floating drilling operations on a 

dynamically positioned drillship, 

Maintain an appropriate vessel heading to provide for downwind diversion. 

§ 250.433 What are the diverter actuation and testing requirements? 

When you install the diverter system, you must actuate the diverter 

sealing element, diverter valves, and 

diverter-control systems and control 

stations. You must also flow-test the 

vent lines. 

(a) For drilling operations with a surface wellhead configuration, you must 

actuate the diverter system at least 

once every 24-hour period after the initial test. After you have nippled up on 

conductor casing, you must pressuretest the diverter-sealing element and 

diverter valves to a minimum of 200 

psi. While the diverter is installed, you 

must conduct subsequent pressure 

tests within 7 days after the previous 

test. 

(b) For floating drilling operations 

with a subsea BOP stack, you must actuate the diverter system within 7 days 

after the previous actuation. 

(c) You must alternate actuations 

and tests between control stations. 

§ 250.434 What are the recordkeeping 

requirements for diverter actuations and tests? 

You must record the time, date, and 

results of all diverter actuations and 

tests in the driller’s report. In addition, you must: 

(a) Record the diverter pressure test 

on a pressure chart; 

(b) Require your onsite representative to sign and date the pressure test 

chart; 

(c) Identify the control station used 

during the test or actuation; 

(d) Identify problems or irregularities observed during the testing or actuations and record actions taken to 

remedy the problems or irregularities; 

and 

(e) Retain all pressure charts and reports pertaining to the diverter tests 

and actuations at the facility for the 

duration of drilling the well. 

BLOWOUT PREVENTER (BOP) SYSTEM

REQUIREMENTS

§ 250.440 What are the general requirements for BOP systems and system 

components? 

You must design, install, maintain, 

test, and use the BOP system and system components to ensure well control. 

The working-pressure rating of each 

BOP component must exceed maximum 

anticipated surface pressures. The BOP 

system includes the BOP stack and associated BOP systems and equipment. 

§ 250.441 What are the requirements 

for a surface BOP stack? 

(a) When you drill with a surface 

BOP stack, you must install the BOP 

system before drilling below surface 

casing. The surface BOP stack must include at least four remote-controlled, 

hydraulically operated BOPs, consisting of an annular BOP, two BOPs 

equipped with pipe rams, and one BOP 

equipped with blind or blind-shear 

rams. 

(b) Your surface BOP stack must include at least four remote-controlled, 

hydraulically operated BOPs consisting 

of an annular BOP, two BOPs equipped 

with pipe rams, and one BOP equipped 

with blind-shear rams. The blind-shear 

rams must be capable of shearing the 

drill pipe that is in the hole. 

(c) You must install an accumulator 

system that provides 1.5 times the volume of fluid capacity necessary to 

close and hold closed all BOP components. The system must perform with a 

minimum pressure of 200 psi above the 

precharge pressure without assistance 

from a charging system. If you supply 

the accumulator regulators by rig air 

and do not have a secondary source of 

pneumatic supply, you must equip the 

regulators with manual overrides or 


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Safety & Environmental Enforcement, Interior § 250.442 

other devices to ensure capability of 

hydraulic operations if rig air is lost. 

(d) In addition to the stack and accumulator system, you must install the 

associated BOP systems and equipment 

required by the regulations in this subpart. 

§ 250.442 What are the requirements 

for a subsea BOP system? 

When you drill with a subsea BOP 

system, you must install the BOP system before drilling below the surface 

casing. The District Manager may require you to install a subsea BOP system before drilling below the conductor casing if proposed casing setting 

depths or local geology indicate the 

need. The table in this paragraph outlines your requirements. 

When drilling with a subsea BOP system, you must: Additional requirements 

(a) Have at least four remote-controlled, hydraulically operated 

BOPs.

You must have at least one annular BOP, two BOPs equipped 

with pipe rams, and one BOP equipped with blind-shear 

rams. The blind-shear rams must be capable of shearing 

any drill pipe (including workstring and tubing) in the hole 

under maximum anticipated surface pressures. 

(b) Have an operable dual-pod control system to ensure proper 

and independent operation of the BOP system.

(c) Have an accumulator system to provide fast closure of the 

BOP components and to operate all critical functions in case 

of a loss of the power fluid connection to the surface.

The accumulator system must meet or exceed the provisions 

of Section 13.3, Accumulator Volumetric Capacity, in API RP 

53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (as incorporated by reference in § 250.198). The District Manager may approve a 

suitable alternate method. 

(d) Have a subsea BOP stack equipped with remotely operated 

vehicle (ROV) intervention capability.

At a minimum, the ROV must be capable of closing one set of 

pipe rams, closing one set of blind-shear rams and 

unlatching the LMRP. 

(e) Maintain an ROV and have a trained ROV crew on each 

drilling rig on a continuous basis once BOP deployment has 

been initiated from the rig until recovered to the surface. The 

crew must examine all ROV related well-control equipment 

(both surface and subsea) to ensure that it is properly maintained and capable of shutting in the well during emergency 

operations.

The crew must be trained in the operation of the ROV. The 

training must include simulator training on stabbing into an 

ROV intervention panel on a subsea BOP stack. 

(f) Provide autoshear and deadman systems for dynamically 

positioned rigs.

(1) Autoshear system means a safety system that is designed 

to automatically shut in the wellbore in the event of a disconnect of the LMRP. When the autoshear is armed, a disconnect of the LMRP closes, at a minimum, one set of blindshear rams. This is considered a ‘‘rapid discharge’’ system. 

(2) Deadman System means a safety system that is designed 

to automatically close, at a minimum, one set of blind-shear 

rams in the event of a simultaneous absence of hydraulic 

supply and signal transmission capacity in both subsea control pods. This is considered a ‘‘rapid discharge’’ system. 

(3) You may also have an acoustic system as a secondary 

control system. If you intend to install an acoustic control 

system, you must demonstrate to BSEE as part of the information submitted under § 250.416 that the acoustic system 

will function in the proposed environment and conditions. 

(g) Have operational or physical barrier(s) on BOP control panels to prevent accidental disconnect functions.Incorporate enable buttons on control panels to ensure twohanded operation for all critical functions. 

(h) Clearly label all control panels for the subsea BOP system Label other BOP control panels such as hydraulic control 

panel. 

(i) Develop and use a management system for operating the 

BOP system, including the prevention of accidental or unplanned disconnects of the system.

The management system must include written procedures for 

operating the BOP stack and LMRP (including proper techniques to prevent accidental disconnection of these components) and minimum knowledge requirements for personnel 

authorized to operate and maintain BOP components. 

(j) Establish minimum requirements for personnel authorized to 

operate critical BOP equipment.

Personnel must have: 

(1) Training in deepwater well control theory and practice according to the requirements of 30 CFR 250, subpart O; and 

(2) A comprehensive knowledge of BOP hardware and control 

systems. 

(k) Before removing the marine riser, displace the fluid in the 

riser with seawater.

You must maintain sufficient hydrostatic pressure or take other 

suitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition. 


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§ 250.443 30 CFR Ch. II (7–1–13 Edition) 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50893, Aug. 22, 2012] 

§ 250.443 What associated systems and 

related equipment must all BOP 

systems include? 

All BOP systems must include the 

following associated systems and related equipment: 

(a) An automatic backup to the primary accumulator-charging system. 

The power source must be independent 

from the power source for the primary 

accumulator-charging system. The 

independent power source must possess 

sufficient capability to close and hold 

closed all BOP components. 

(b) At least two BOP control stations. One station must be on the drilling floor. You must locate the other 

station in a readily accessible location 

away from the drilling floor. 

(c) Side outlets on the BOP stack for 

separate kill and choke lines. If your 

stack does not have side outlets, you 

must install a drilling spool with side 

outlets. 

(d) A choke and a kill line on the 

BOP stack. You must equip each line 

with two full-opening valves, one of 

which must be remote-controlled. For 

a subsea BOP system, both valves in 

each line must be remote-controlled. In 

addition: 

(1) You must install the choke line 

above the bottom ram; 

(2) You may install the kill line 

below the bottom ram; and 

(3) For a surface BOP system, on the 

kill line you may install a check valve 

and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be 

readily accessible and you must install 

the check valve between the manual 

valves and the pump. 

(e) A fill-up line above the uppermost 

BOP. 

(f) Locking devices installed on the 

ram-type BOPs. 

(g) A wellhead assembly with a rated 

working pressure that exceeds the 

maximum anticipated wellhead pressure. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50893, Aug. 22, 2012] 

§ 250.444 What are the choke manifold 

requirements? 

(a) Your BOP system must include a 

choke manifold that is suitable for the 

anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of 

drilling fluids and well fluids that you 

may encounter. 

(b) Choke manifold components must 

have a rated working pressure at least 

as great as the rated working pressure 

of the ram BOPs. If your choke manifold has buffer tanks downstream of 

choke assemblies, you must install isolation valves on any bleed lines. 

(c) Valves, pipes, flexible steel hoses, 

and other fittings upstream of the 

choke manifold must have a rated 

working pressure at least as great as 

the rated working pressure of the ram 

BOPs. 

§ 250.445 What are the requirements 

for kelly valves, inside BOPs, and 

drill-string safety valves? 

You must use or provide the following BOP equipment during drilling 

operations: 

(a) A kelly valve installed below the 

swivel (upper kelly valve); 

(b) A kelly valve installed at the bottom of the kelly (lower kelly valve). 

You must be able to strip the lower 

kelly valve through the BOP stack; 

(c) If you drill with a mud motor and 

use drill pipe instead of a kelly, you 

must install one kelly valve above, and 

one strippable kelly valve below, the 

joint of drill pipe used in place of a 

kelly; 

(d) On a top-drive system equipped 

with a remote-controlled valve, you 

must install a strippable kelly-type 

valve below the remote-controlled 

valve; 

(e) An inside BOP in the open position located on the rig floor. You must 

be able to install an inside BOP for 

each size connection in the drill string; 

(f) A drill-string safety valve in the 

open position located on the rig floor. 

You must have a drill-string safety 

valve available for each size connection 

in the drill string; 

(g) When running casing, you must 

have a safety valve in the open position 


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Safety & Environmental Enforcement, Interior § 250.448 

available on the rig floor to fit the casing string being run in the hole; 

(h) All required manual and remotecontrolled kelly valves, drill-string 

safety valves, and comparable-type 

valves (i.e., kelly-type valve in a topdrive system) must be essentially fullopening; and 

(i) The drilling crew must have ready 

access to a wrench to fit each manual 

valve. 

§ 250.446 What are the BOP maintenance and inspection requirements? 

(a) You must maintain and inspect 

your BOP system to ensure that the 

equipment functions properly. The 

BOP maintenance and inspections 

must meet or exceed the provisions of 

Sections 17.10 and 18.10, Inspections; 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

Recommended Practices for Blowout 

Prevention Equipment Systems for 

Drilling Wells (incorporated by reference as specified in §250.198). You 

must document how you met or exceeded the provisions of Sections 17.10 and 

18.10, Inspections; Sections 17.11 and 

18.11, Maintenance; and Sections 17.12 

and 18.12, Quality Management, described in API RP 53, record the results 

of your BOP inspections and maintenance actions, and make the records 

available to BSEE upon request. You 

must maintain your records on the rig 

for 2 years from the date the records 

are created, or for a longer period if directed by BSEE; 

(b) You must visually inspect your 

surface BOP system on a daily basis. 

You must visually inspect your subsea 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use television cameras to inspect subsea equipment. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50893, Aug. 22, 2012] 

§ 250.447 When must I pressure test 

the BOP system? 

You must pressure test your BOP 

system (this includes the choke manifold, kelly valves, inside BOP, and 

drill-string safety valve): 

(a) When installed; 

(b) Before 14 days have elapsed since 

your last BOP pressure test. You must 

begin to test your BOP system before 

midnight on the 14th day following the 

conclusion of the previous test. However, the District Manager may require 

more frequent testing if conditions or 

BOP performance warrant; and 

(c) Before drilling out each string of 

casing or a liner. The District Manager 

may allow you to omit this test if you 

didn’t remove the BOP stack to run the 

casing string or liner and the required 

BOP test pressures for the next section 

of the hole are not greater than the 

test pressures for the previous BOP 

test. You must indicate in your APD 

which casing strings and liners meet 

these criteria. 

§ 250.448 What are the BOP pressure 

tests requirements? 

When you pressure test the BOP system, you must conduct a low-pressure 

and a high-pressure test for each BOP 

component. You must conduct the lowpressure test before the high-pressure 

test. Each individual pressure test 

must hold pressure long enough to 

demonstrate that the tested component(s) holds the required pressure. Required test pressures are as follows: 

(a) Low-pressure test. All low-pressure 

tests must be between 200 and 300 psi. 

Any initial pressure above 300 psi must 

be bled back to a pressure between 200 

and 300 psi before starting the test. If 

the initial pressure exceeds 500 psi, you 

must bleed back to zero and reinitiate 

the test. 

(b) High-pressure test for ram-type 

BOPs, the choke manifold, and other 

BOP components. The high-pressure test 

must equal the rated working pressure 

of the equipment or be 500 psi greater 

than your calculated maximum anticipated surface pressure (MASP) for the 

applicable section of hole. Before you 

may test BOP equipment to the MASP 

plus 500 psi, the District Manager must 

have approved those test pressures in 

your APD. 

(c) High pressure test for annular-type 

BOPs. The high pressure test must 

equal 70 percent of the rated working 

pressure of the equipment or to a pressure approved in your APD. 

(d) Duration of pressure test. Each test 

must hold the required pressure for 5 


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§ 250.449 30 CFR Ch. II (7–1–13 Edition) 

minutes. However, for surface BOP systems and surface equipment of a subsea 

BOP system, a 3-minute test duration 

is acceptable if you record your test 

pressures on the outermost half of a 4- 

hour chart, on a 1-hour chart, or on a 

digital recorder. If the equipment does 

not hold the required pressure during a 

test, you must correct the problem and 

retest the affected component(s). 

§ 250.449 What additional BOP testing 

requirements must I meet? 

You must meet the following additional BOP testing requirements: 

(a) Use water to test a surface BOP 

system; 

(b) Stump test a subsea BOP system 

before installation. You must use 

water to conduct this test. You may 

use drilling fluids to conduct subsequent tests of a subsea BOP system. 

You must perform the initial subsea 

BOP test on the seafloor within 30 days 

of the stump test. 

(c) Alternate tests between control 

stations and pods; 

(d) Pressure test the blind or blindshear ram BOP during stump tests and 

at all casing points; 

(e) The interval between any blind or 

blind-shear ram BOP pressure tests 

may not exceed 30 days; 

(f) Pressure test variable bore-pipe 

ram BOPs against the largest and 

smallest sizes of pipe in use, excluding 

drill collars and bottom-hole tools; 

(g) Pressure test affected BOP components following the disconnection or 

repair of any well-pressure containment seal in the wellhead or BOP stack 

assembly; 

(h) Function test annular and ram 

BOPs every 7 days between pressure 

tests; 

(i) Actuate safety valves assembled 

with proper casing connections before 

running casing; 

(j) Test all ROV intervention functions on your subsea BOP stack during 

the stump test. Each ROV must be 

fully compatible with the BOP stack 

ROV intervention panels. You must 

also test and verify closure of at least 

one set of rams during the initial test 

on the seafloor through an ROV hot 

stab. You must submit test procedures, 

including how you will test each ROV 

intervention function, with your APD 

or APM for BSEE District Manager approval. You must: 

(1) Ensure that the ROV hot stabs are 

function tested and are capable of actuating, at a minimum, one set of pipe 

rams, one set of blind-shear rams, and 

unlatching the Lower Marine Riser 

Package (LMRP); 

(2) Notify the appropriate BSEE District Manager a minimum of 72 hours 

prior to the stump test and initial test 

on the seafloor; and 

(3) Document all your test results 

and make them available to BSEE 

upon request; 

(k) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system and 

verify closure of at least one set of 

blind-shear rams during the initial test 

on the seafloor. When you conduct the 

initial deadman system test on the 

seafloor you must ensure the well is secure and, if hydrocarbons have been 

present, appropriate barriers are in 

place to isolate hydrocarbons from the 

wellhead. You must also have an ROV 

on bottom during the test. 

(1) You must submit test procedures 

with your APD or APM for District 

Manager approval. The procedures for 

these function tests must include documentation of the controls and circuitry 

of the system utilized during each test. 

The procedure must also describe how 

the ROV will be utilized during this operation. 

(2) You must document all your test 

results and make them available to 

BSEE upon request. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50893, Aug. 22, 2012] 

§ 250.450 What are the recordkeeping 

requirements for BOP tests? 

You must record the time, date, and 

results of all pressure tests, actuations, 

and inspections of the BOP system, 

system components, and marine riser 

in the driller’s report. In addition, you 

must: 

(a) Record BOP test pressures on 

pressure charts; 

(b) Require your onsite representative to sign and date BOP test charts 

and reports as correct; 

(c) Document the sequential order of 

BOP and auxiliary equipment testing 


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Safety & Environmental Enforcement, Interior § 250.456 

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. 

§ 250.451 What must I do in certain situations involving BOP equipment 

or systems? 

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 required pressure during 

a test, 

Correct the problem and retest the affected equipment. 

(b) Need to repair or replace a surface or subsea BOP system, First place the well in a 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 well-control problems 

such as lost circulation, formation fluid influx, or stuck drill 

pipe, 

Record the reason for postponing the test in the driller’s report 

and conduct the required BOP test on the first trip out of the 

hole. 

(d) BOP control station or pod that does not function properly, Suspend further drilling operations until that station or pod is 

operable. 

(e) Want to drill with a tapered drill-string, Install two or more sets of 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 rated working pressure 

less than the anticipated surface pressure, 

Demonstrate that your well control procedures or the anticipated well conditions will not place demands above its rated 

working pressure and obtain approval from the District Manager. 

(h) Use a subsea BOP system in an ice-scour area, Install the BOP stack in a well cellar. The well cellar must be 

deep enough to ensure that the top of the stack is below the 

deepest probable ice-scour depth. 

(i) You activate blind-shear rams or casing shear rams during a 

well control situation, in which pipe or casing is sheared, 

Retrieve, physically inspect, and conduct a full pressure test of 

the BOP stack after the situation is fully controlled. 

(j) Need to remove the BOP stack Have a minimum of two barriers in place prior to BOP removal. 

The BSEE District Manager may require additional barriers. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50894, Aug. 22, 2012] 

DRILLING FLUID REQUIREMENTS

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

You must design and implement your 

drilling fluid program to prevent the 

loss of well control. This program must 

address drilling fluid safe practices, 

testing and monitoring equipment, 

drilling fluid quantities, and drilling 

fluid-handling areas. 

§ 250.456 What safe practices must the 

drilling fluid program follow? 

Your drilling fluid program must include the following safe practices: 

(a) Before starting out of the hole 

with drill pipe, you must properly condition the drilling fluid. You must circulate a volume of drilling fluid equal 

to the annular volume with the drill 

pipe just off-bottom. You may omit 

this practice if documentation in the 

driller’s report shows: 

(1) No indication of formation fluid 

influx before starting to pull the drill 

pipe from the hole; 

(2) The weight of returning drilling 

fluid is within 0.2 pounds per gallon (1.5 

pounds per cubic foot) of the drilling 

fluid entering the hole; and 

(3) Other drilling fluid properties are 

within the limits established by the 

program approved in the APD. 


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§ 250.457 30 CFR Ch. II (7–1–13 Edition) 

(b) Record each time you circulate 

drilling fluid in the hole in the driller’s 

report; 

(c) When coming out of the hole with 

drill pipe, you must fill the annulus 

with drilling fluid before the hydrostatic pressure decreases by 75 psi, or 

every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. You must calculate the 

number of stands of drill pipe and drill 

collars that you may pull before you 

must fill the hole. You must also calculate the equivalent drilling fluid volume needed to fill the hole. Both sets 

of numbers must be posted near the 

driller’s station. You must use a mechanical, volumetric, or electronic device to measure the drilling fluid required to fill the hole; 

(d) You must run and pull drill pipe 

and downhole tools at controlled rates 

so you do not swab or surge the well; 

(e) When there is an indication of 

swabbing or influx of formation fluids, 

you must take appropriate measures to 

control the well. You must circulate 

and condition the well, on or near-bottom, unless well or drilling-fluid conditions prevent running the drill pipe 

back to the bottom; 

(f) You must calculate and post near 

the driller’s console the maximum 

pressures that you may safely contain 

under a shut-in BOP for each casing 

string. The pressures posted must consider the surface pressure at which the 

formation at the shoe would break 

down, the rated working pressure of 

the BOP stack, and 70 percent of casing 

burst (or casing test as approved by the 

District Manager). As a minimum, you 

must post the following two pressures: 

(1) The surface pressure at which the 

shoe would break down. This calculation must consider the current drilling 

fluid weight in the hole; and 

(2) The lesser of the BOP’s rated 

working pressure or 70 percent of casing-burst pressure (or casing test otherwise approved by the District Manager); 

(g) You must install an operable 

drilling fluid-gas separator and 

degasser before you begin drilling operations. You must maintain this equipment throughout the drilling of the 

well; 

(h) Before pulling drill-stem test 

tools from the hole, you must circulate 

or reverse-circulate the test fluids in 

the hole. If circulating out test fluids 

is not feasible, you may bullhead test 

fluids out of the drill-stem test string 

and tools with an appropriate kill 

weight fluid; 

(i) When circulating, you must test 

the drilling fluid at least once each 

tour, or more frequently if conditions 

warrant. Your tests must conform to 

industry-accepted practices and include density, viscosity, and gel 

strength; hydrogenion concentration; 

filtration; and any other tests the District Manager requires for monitoring 

and maintaining drilling fluid quality, 

prevention of downhole equipment 

problems and for kick detection. You 

must record the results of these tests 

in the drilling fluid report; 

(j) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APD or APM your 

reasons for displacing the kill-weight 

fluid and provide detailed step-by-step 

written procedures describing how you 

will safely displace these fluids. The 

step-by-step displacement procedures 

must address the following: 

(1) Number and type of independent 

barriers, as described in §250.420(b)(3), 

that are in place for each flow path 

that requires such barriers, 

(2) Tests you will conduct to ensure 

integrity of independent barriers, 

(3) BOP procedures you will use while 

displacing kill-weight fluids, and 

(4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore; and 

(k) In areas where permafrost and/or 

hydrate zones are present or may be 

present, you must control drilling fluid 

temperatures to drill safely through 

those zones. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50894, Aug. 22, 2012] 

§ 250.457 What equipment is required 

to monitor drilling fluids? 

Once you establish drilling fluid returns, you must install and maintain 

the following drilling fluid-system 


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Safety & Environmental Enforcement, Interior § 250.459 

monitoring equipment throughout subsequent drilling operations. This equipment must have the following indicators on the rig floor: 

(a) Pit level indicator to determine 

drilling fluid-pit volume gains and 

losses. This indicator must include 

both a visual and an audible warning 

device; 

(b) Volume measuring device to accurately determine drilling fluid volumes 

required to fill the hole on trips; 

(c) Return indicator devices that indicate the relationship between drilling fluid-return flow rate and pump 

discharge rate. This indicator must include both a visual and an audible 

warning device; and 

(d) Gas-detecting equipment to monitor the drilling fluid returns. The indicator may be located in the drilling 

fluid-logging compartment or on the 

rig floor. If the indicators are only in 

the logging compartment, you must 

continually man the equipment and 

have a means of immediate communication with the rig floor. If the indicators are on the rig floor only, you 

must install an audible alarm. 

§ 250.458 What quantities of drilling 

fluids are required? 

(a) You must use, maintain, and replenish quantities of drilling fluid and 

drilling fluid materials at the drill site 

as necessary to ensure well control. 

You must determine those quantities 

based on known or anticipated drilling 

conditions, rig storage capacity, 

weather conditions, and estimated 

time for delivery. 

(b) You must record the daily inventories of drilling fluid and drilling fluid 

materials, including weight materials 

and additives in the drilling fluid report. 

(c) If you do not have sufficient quantities of drilling fluid and drilling fluid 

material to maintain well control, you 

must suspend drilling operations. 

§ 250.459 What are the safety requirements for drilling fluid-handling 

areas? 

You must classify drilling fluid-handling areas according to API RP 500, 

Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class I, Division 1 and Division 

2 (as incorporated by reference in 

§250.198); or API RP 505, Recommended 

Practice for Classification of Locations 

for Electrical Installations at Petroleum Facilities, Classified as Class 1, 

Zone 0, Zone 1, and Zone 2 (as incorporated by reference in §250.198). In 

areas where dangerous concentrations 

of combustible gas may accumulate, 

you must install and maintain a ventilation system and gas monitors. 

Drilling fluid-handling areas must have 

the following safety equipment: 

(a) A ventilation system capable of 

replacing the air once every 5 minutes 

or 1.0 cubic feet of air-volume flow per 

minute, per square foot of area, whichever is greater. In addition: 

(1) If natural means provide adequate 

ventilation, then a mechanical ventilation system is not necessary; 

(2) If a mechanical system does not 

run continuously, then it must activate when gas detectors indicate the 

presence of 1 percent or more of combustible gas by volume; and 

(3) If discharges from a mechanical 

ventilation system may be hazardous, 

then you must maintain the drilling 

fluid-handling area at a negative pressure. You must protect the negative 

pressure area by using at least one of 

the following: a pressure-sensitive 

alarm, open-door alarms on each access 

to the area, automatic door-closing devices, air locks, or other devices approved by the District Manager; 

(b) Gas detectors and alarms except 

in open areas where adequate ventilation is provided by natural means. You 

must test and recalibrate gas detectors 

quarterly. No more than 90 days may 

elapse between tests; 

(c) Explosion-proof or pressurized 

electrical equipment to prevent the ignition of explosive gases. Where you 

use air for pressuring equipment, you 

must locate the air intake outside of 

and as far as practicable from hazardous areas; and 

(d) Alarms that activate when the 

mechanical ventilation system fails. 


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§ 250.460 30 CFR Ch. II (7–1–13 Edition) 

OTHER DRILLING REQUIREMENTS

§ 250.460 What are the requirements 

for conducting a well test? 

(a) If you intend to conduct a well 

test, you must include your projected 

plans for the test with your APD (form 

BSEE–0123) or in an Application for 

Permit to Modify (APM) (form BSEE– 

0124). Your plans must include at least 

the following information: 

(1) Estimated flowing and shut-in 

tubing pressures; 

(2) Estimated flow rates and cumulative volumes; 

(3) Time duration of flow, buildup, 

and drawdown periods; 

(4) Description and rating of surface 

and subsurface test equipment; 

(5) Schematic drawing, showing the 

layout of test equipment; 

(6) Description of safety equipment, 

including gas detectors and fire-fighting equipment; 

(7) Proposed methods to handle or 

transport produced fluids; and 

(8) Description of the test procedures. 

(b) You must give the District Manager at least 24-hours notice before 

starting a well test. 

§ 250.461 What are the requirements 

for directional and inclination surveys? 

For this subpart, BSEE classifies a 

well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical. 

(a) Survey requirements for a vertical 

well. (1) You must conduct inclination 

surveys on each vertical well and 

record the results. Survey intervals 

may not exceed 1,000 feet during the 

normal course of drilling; 

(2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally 

record the results in electronic format: 

(i) Within 500 feet of setting surface 

or intermediate casing; 

(ii) Within 500 feet of setting any 

liner; and 

(iii) When you reach total depth. 

(b) Survey requirements for directional 

well. You must conduct directional surveys on each directional well and 

digitally record the results. Surveys 

must give both inclination and azimuth at intervals not to exceed 500 feet 

during the normal course of drilling. 

Intervals during angle-changing portions of the hole may not exceed 100 

feet. 

(c) Measurement while drilling. You 

may use measurement-while-drilling 

technology if it meets the requirements of this section. 

(d) Composite survey requirements. (1) 

Your composite directional survey 

must show the interval from the bottom of the conductor casing to total 

depth. In the absence of conductor casing, the survey must show the interval 

from the bottom of the drive or structural casing to total depth; and 

(2) You must correct all surveys to 

Universal-Transverse-Mercator-Gridnorth or Lambert-Grid-north after 

making the magnetic-to-true-north 

correction. Surveys must show the 

magnetic and grid corrections used and 

include a listing of the directionally 

computed inclinations and azimuths. 

(e) If you drill within 500 feet of an 

adjacent lease, the Regional Supervisor 

may require you to furnish a copy of 

the well’s directional survey to the affected leaseholder. This could occur 

when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights. 

§ 250.462 What are the requirements 

for well-control drills? 

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. 


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Safety & Environmental Enforcement, Interior § 250.466 

(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) BSEE ordered drill. A BSEE authorized representative may require 

you to conduct a well control drill during a BSEE inspection. The BSEE representative will consult with your onsite representative before requiring the 

drill. 

§ 250.463 Who establishes field drilling 

rules? 

(a) The District Manager may establish field drilling rules different from 

the requirements of this subpart when 

geological and engineering information 

shows that specific operating requirements are appropriate. You must comply with field drilling rules and nonconflicting requirements of this subpart. The District Manager may amend 

or cancel field drilling rules at any 

time. 

(b) You may request the District 

Manager to establish, amend, or cancel 

field drilling rules. 

APPLYING FOR A PERMIT TO MODIFY AND

WELL RECORDS

§ 250.465 When must I submit an Application for Permit to Modify 

(APM) or an End of Operations Report to BSEE? 

(a) You must submit an APM (form 

BSEE–0124) or an End of Operations Report (form BSEE–0125) and other materials to the Regional Supervisor as 

shown in the following table. You must 

also submit a public information copy 

of each form. 

When you . . . Then you must . . . And . . . 

(1) Intend to revise your drilling 

plan, change major drilling 

equipment, or plugback, 

Submit form BSEE–0124 or 

request oral approval, 

Receive written or oral approval from the District Manager 

before you begin the intended operation. If you get an approval, you must submit form BSEE–0124 no later than the 

end of the 3rd business day following the oral approval. In 

all cases, or you must meet the additional requirements in 

paragraph (b) of this section. 

(2) Determine a well’s final surface location, water depth, 

and the rotary kelly bushing 

elevation, 

Immediately Submit a form 

BSEE–0124, 

Submit a plat certified by a registered land surveyor that 

meets the requirements of § 250.412. 

(3) Move a drilling unit from a 

wellbore before completing a 

well, 

Submit forms BSEE–0124 and 

BSEE–0125 within 30 days 

after the suspension of 

wellbore operations, 

Submit appropriate copies of the well records. 

(b) If you intend to perform any of 

the actions specified in paragraph (a)(1) 

of this section, you must meet the following additional requirements: 

(1) Your APM (Form BSEE–0124) 

must contain a detailed statement of 

the proposed work that would materially change from the approved APD. 

The submission of your APM must be 

accompanied by payment of the service 

fee listed in §250.125; 

(2) Your form BSEE–0124 must include the present status of the well, 

depth of all casing strings set to date, 

well depth, present production zones 

and productive capability, and all 

other information specified; and 

(3) Within 30 days after completing 

this work, you must submit form 

BSEE–0124 with detailed information 

about the work to the District Manager, unless you have already provided 

sufficient information in a Well Activity Report, form BSEE–0133 

(§250.468(b)). 

§ 250.466 What records must I keep? 

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 §250.467. 

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; 


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§ 250.467 30 CFR Ch. II (7–1–13 Edition) 

(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 Manager in the interests of 

resource evaluation, waste prevention, 

conservation of natural resources, and 

the protection of correlative rights, 

safety, and environment. 

§ 250.467 How long must I keep 

records? 

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, diverter tests, and BOP 

tests, 

Two years after the completion of drilling operations. 

(c) Completion of a well or of any workover activity that materially alters the completion configuration or affects a hydrocarbon-bearing zone, 

You permanently plug and abandon the well or until you forward the records with a lease assignment. 

§ 250.468 What well records am I required to submit? 

(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 BSEE. 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 BSEE–0133, Well Activity Report, 

to the District Manager on a weekly 

basis. 

(c) For drilling operations in the Pacific or Alaska OCS Regions, you must 

submit form BSEE–0133, Well Activity 

Report, to the District Manager on a 

daily basis. 

§ 250.469 What other well records 

could I be required to submit? 

The District Manager or Regional 

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. 

HYDROGEN SULFIDE

§ 250.490 Hydrogen sulfide. 

(a) What precautions must I take when 

operating in an H2S area? You must: 

(1) Take all necessary and feasible 

precautions and measures to protect 

personnel from the toxic effects of H2S 

and to mitigate damage to property 

and the environment caused by H2S. 

You must follow the requirements of 

this section when conducting drilling, 

well-completion/well-workover, and 

production operations in zones with 

H2S present and when conducting operations in zones where the presence of 

H2S is unknown. You do not need to 

follow these requirements when operating in zones where the absence of H2S 

has been confirmed; and 

(2) Follow your approved contingency 

plan. 

(b) Definitions. Terms used in this 

section have the following meanings: 

Facility means a vessel, a structure, 

or an artificial island used for drilling, 

well-completion, 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 


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Safety & Environmental Enforcement, Interior § 250.490 

atmospheric concentrations of 20 ppm 

or more of H2S; or 

(2) Drilling in the surrounding areas 

and correlation of geological and seismic data with equivalent stratigraphic 

units have confirmed an absence of H2S 

throughout the area to be drilled. 

H2S present means that drilling, logging, coring, testing, or producing operations have confirmed the presence 

of H2S in concentrations and volumes 

that could potentially result in atmospheric concentrations of 20 ppm or 

more of H2S. 

H2S unknown means the designation 

of a zone or geologic formation where 

neither the presence nor absence of H2S 

has been confirmed. 

Well-control fluid means drilling mud 

and completion or workover fluid as 

appropriate to the particular operation 

being conducted. 

(c) Classifying an area for the presence 

of H2S. You must: 

(1) Request and obtain an approved 

classification for the area from the Regional Supervisor before you begin operations. Classifications are ‘‘H2S absent,’’ H2S present,’’ or ‘‘H2S unknown’’; 

(2) Submit your request with your 

application for permit to drill; 

(3) Support your request with available information such as geologic and 

geophysical data and correlations, well 

logs, formation tests, cores and analysis of formation fluids; and 

(4) Submit a request for reclassification of a zone when additional data indicate a different classification is needed. 

(d) What do I do if conditions change? 

If you encounter H2S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not 

previously classified as having H2S 

present, you must immediately notify 

BSEE and begin to follow requirements 

for areas with H2S present. 

(e) What are the requirements for conducting simultaneous operations? When 

conducting any combination of drilling, well-completion, well-workover, 

and production operations simultaneously, you must follow the requirements in the section applicable to each 

individual operation. 

(f) Requirements for submitting an H2S 

Contingency Plan. Before you begin operations, you must submit an H2S Contingency Plan to the District Manager 

for approval. Do not begin operations 

before the District Manager approves 

your plan. You must keep a copy of the 

approved plan in the field, and you 

must follow the plan at all times. Your 

plan must include: 

(1) Safety procedures and rules that 

you will follow concerning equipment, 

drills, and smoking; 

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

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

personnel; 

(4) Other key positions, how these positions fit into your organization, and 

what the functions, duties, and responsibilities of those job positions are; 

(5) Actions that you will take when 

the concentration of H2S in the atmosphere reaches 20 ppm, who will be responsible for those actions, and a description of the audible and visual 

alarms to be activated; 

(6) Briefing areas where personnel 

will assemble during an H2S alert. You 

must have at least two briefing areas 

on each facility and use the briefing 

area that is upwind of the H2S source 

at any given time; 

(7) Criteria you will use to decide 

when to evacuate the facility and procedures you will use to safely evacuate 

all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H2S alerts, describe the 

types of H2S emergencies during which 

you consider the risk of helicopter activity to be acceptable and the precautions you will take during the 

flights; 

(8) Procedures you will use to safely 

position all vessels attendant to the facility. Indicate where you will locate 

the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use 

to safely relocate the vessels in an 

emergency; 

(9) How you will provide protectivebreathing 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 


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§ 250.490 30 CFR Ch. II (7–1–13 Edition) 

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; 


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(iv) Restrictions and corrective 

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

(v) Basic first-aid procedures applicable to victims of H2S exposure. During 

all drills and training sessions, you 

must address procedures for rescue and 

first aid for H2S victims; 

(vi) Location of: 

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

(B) Resuscitators; and 

(C) Litter or other device on the facility. 

(vii) Meaning of all warning signals. 

(5) Do I need to post safety information? 

You must prominently post safety information on the facility and on vessels serving the facility (i.e., basic 

first-aid, escape routes, instructions 

for use of life boats, etc.). 

(h) Drills. (1) When and how often do I 

need to conduct drills on H2S safety discussions on the facility? You must: 

(i) Conduct a drill for each person at 

the facility during normal duty hours 

at least once every 7-day period. The 

drills must consist of a dry-run performance of personnel activities related to assigned jobs. 

(ii) At a safety meeting or other 

meetings of all personnel, discuss drill 

performance, new H2S considerations 

at the facility, and other updated H2S 

information at least monthly. 

(2) What documentation do I need? You 

must keep records of attendance for: 

(i) Drilling, well-completion, and 

well-workover operations at the facility until operations are completed; and 

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

1 year. 

(i) Visual and audible warning systems: 

(1) How must I install wind direction 

equipment? You must install wind-direction equipment in a location visible 

at all times to individuals on or in the 

immediate vicinity of the facility. 

(2) When do I need to display operational danger signs, display flags, or activate visual or audible alarms? 

(i) You must display warning signs at 

all times on facilities with wells capable of producing H2S and on facilities 

that process gas containing H2S in concentrations of 20 ppm or more. 

(ii) In addition to the signs, you must 

activate audible alarms and display 

flags or activate flashing red lights 

when atmospheric concentration of H2S 

reaches 20 ppm. 

(3) What are the requirements for signs? 

Each sign must be a high-visibility yellow color with black lettering as follows: 

Letter height Wording 

12 inches ................................ Danger. 

Poisonous Gas. 

Hydrogen Sulfide. 

7 inches .................................. Do not approach if red flag is 

flying. 

(Use appropriate wording at 

right).

Do not approach if red lights 

are flashing. 

(4) May I use existing signs? You may 

use existing signs containing the words 

‘‘Danger-Hydrogen Sulfide-H2S,’’ provided the words ‘‘Poisonous Gas. Do 

Not Approach if Red Flag is Flying’’ or 

‘‘Red Lights are Flashing’’ in lettering 

of a minimum of 7 inches in height are 

displayed on a sign immediately adjacent to the existing sign. 

(5) What are the requirements for flashing lights or flags? You must activate a 

sufficient number of lights or hoist a 

sufficient number of flags to be visible 

to vessels and aircraft. Each light must 

be of sufficient intensity to be seen by 

approaching vessels or aircraft any 

time it is activated (day or night). 

Each flag must be red, rectangular, a 

minimum width of 3 feet, and a minimum height of 2 feet. 

(6) What is an audible warning system? 

An audible warning system is a public 

address system or siren, horn, or other 

similar warning device with a unique 

sound used only for H2S. 

(7) Are there any other requirements for 

visual or audible warning devices? Yes, 

you must: 

(i) Illuminate all signs and flags at 

night and under conditions of poor visibility; and 

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

the area. 

(8) What actions must I take when the 

alarms are activated? When the warning 

devices are activated, the designated 

responsible persons must inform personnel of the level of danger and issue 

instructions on the initiation of appropriate protective measures. 


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(j) H2S-detection and H2S monitoring 

equipment: (1) What are the requirements 

for an H2S detection system? An H2S detection system must: 

(i) Be capable of sensing a minimum 

of 10 ppm of H2S in the atmosphere; 

and 

(ii) Activate audible and visual 

alarms when the concentration of H2S 

in the atmosphere reaches 20 ppm. 

(2) Where must I have sensors for drilling, well-completion, and well-workover 

operations? You must locate sensors at 

the: 

(i) Bell nipple; 

(ii) Mud-return line receiver tank 

(possum belly); 

(iii) Pipe-trip tank; 

(iv) Shale shaker; 

(v) Well-control fluid pit area; 

(vi) Driller’s station; 

(vii) Living quarters; and 

(viii) All other areas where H2S may 

accumulate. 

(3) Do I need mud sensors? The District Manager may require mud sensors 

in the possum belly in cases where the 

ambient air sensors in the mud-return 

system do not consistently detect the 

presence of H2S. 

(4) How often must I observe the sensors? During drilling, well-completion 

and well-workover operations, you 

must continuously observe the H2S levels indicated by the monitors in the 

work areas during the following operations: 

(i) When you pull a wet string of drill 

pipe or workover string; 

(ii) When circulating bottoms-up 

after a drilling break; 

(iii) During cementing operations; 

(iv) During logging operations; and 

(v) When circulating to condition 

mud or other well-control fluid. 

(5) Where must I have sensors for production operations? On a platform where 

gas containing H2S of 20 ppm or greater 

is produced, processed, or otherwise 

handled: 

(i) You must have a sensor in rooms, 

buildings, deck areas, or low-laying 

deck areas not otherwise covered by 

paragraph (j)(2) of this section, where 

atmospheric concentrations of H2S 

could reach 20 ppm or more. You must 

have at least one sensor per 400 square 

feet of deck area or fractional part of 

400 square feet; 

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

quarters; 

(iii) You must have a sensor within 10 

feet of each vessel, compressor, wellhead, manifold, or pump, which could 

release enough H2S to result in atmospheric concentrations of 20 ppm at a 

distance of 10 feet from the component; 

(iv) You may use one sensor to detect 

H2S around multiple pieces of equipment, provided the sensor is located no 

more than 10 feet from each piece, except that you need to use at least two 

sensors to monitor compressors exceeding 50 horsepower; 

(v) You do not need to have sensors 

near wells that are shut in at the master valve and sealed closed; 

(vi) When you determine where to 

place sensors, you must consider: 

(A) The location of system fittings, 

flanges, valves, and other devices subject to leaks to the atmosphere; and 

(B) Design factors, such as the type 

of decking and the location of fire 

walls; and 

(vii) The District Manager may require additional sensors or other monitoring capabilities, if warranted by site 

specific conditions. 

(6) How must I functionally test the H2S 

Detectors? (i) Personnel trained to calibrate the particular H2S detector 

equipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm 

of H2S. 

(ii) If the results of any functional 

test are not within 2 ppm or 10 percent, 

whichever is greater, of the applied 

concentration, recalibrate the instrument. 

(7) How often must I test my detectors? 

(i) When conducting drilling, drill stem 

testing, well-completion, or wellworkover operations in areas classified 

as H2S present or H2S unknown, test all 

detectors at least once every 24 hours. 

When drilling, begin functional testing 

before the bit is 1,500 feet (vertically) 

above the potential H2S zone. 

(ii) When conducting production operations, test all detectors at least 

every 14 days between tests. 

(iii) If equipment requires calibration 

as a result of two consecutive functional tests, the District Manager may 

require that H2S-detection and H2SVerDate Mar<15>2010 13:26 Aug 06, 2013 Jkt 229122 PO 00000 Frm 00124 Fmt 8010 Sfmt 8010 Y:\SGML\229122.XXX 229122

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monitoring equipment be functionally 

tested and calibrated more frequently. 

(8) What documentation must I keep? (i) 

You must maintain records of testing 

and calibrations (in the drilling or production operations report, as applicable) at the facility to show the present 

status and history of each device, including dates and details concerning: 

(A) Installation; 

(B) Removal; 

(C) Inspection; 

(D) Repairs; 

(E) Adjustments; and 

(F) Reinstallation. 

(ii) Records must be available for inspection by BSEE personnel. 

(9) What are the requirements for nearby vessels? If vessels are stationed overnight alongside facilities in areas of 

H2S present or H2S unknown, you must 

equip vessels with an H2S-detection 

system that activates audible and visual alarms when the concentration of 

H2S in the atmosphere reaches 20 ppm. 

This requirement does not apply to 

vessels positioned upwind and at a safe 

distance from the facility in accordance with the positioning procedure described in the approved H2S Contingency Plan. 

(10) What are the requirements for nearby facilities? The District Manager may 

require you to equip nearby facilities 

with portable or fixed H2S detector(s) 

and to test and calibrate those detectors. To invoke this requirement, the 

District Manager will consider dispersion modeling results from a possible 

release to determine if 20 ppm H2S concentration levels could be exceeded at 

nearby facilities. 

(11) What must I do to protect against 

SO2 if I burn gas containing H2S? You 

must: 

(i) Monitor the SO2concentration in 

the air with portable or strategically 

placed fixed devices capable of detecting a minimum of 2 ppm of SO2; 

(ii) Take readings at least hourly and 

at any time personnel detect SO2 odor 

or nasal irritation; 

(iii) Implement the personnel protective measures specified in the H2S Contingency Plan if the SO2 concentration 

in the work area reaches 2 ppm; and 

(iv) Calibrate devices every 3 months 

if you use fixed or portable electronic 

sensing devices to detect SO2. 

(12) May I use alternative measures? 

You may follow alternative measures 

instead of those in paragraph (j)(11) of 

this section if you propose and the Regional Supervisor approves the alternative measures. 

(13) What are the requirements for protective-breathing equipment? In an area 

classified as H2S present or H2S unknown, you must: 

(i) Provide all personnel, including 

contractors and visitors on a facility, 

with immediate access to self-contained pressure-demand-type respirators with hoseline capability and 

breathing time of at least 15 minutes. 

(ii) Design, select, use, and maintain 

respirators in conformance with ANSI 

Z88.2 (as specified in §250.198). 

(iii) Make available at least two 

voice-transmission devices, which can 

be used while wearing a respirator, for 

use by designated personnel. 

(iv) Make spectacle kits available as 

needed. 

(v) Store protective-breathing equipment in a location that is quickly and 

easily accessible to all personnel. 

(vi) Label all breathing-air bottles as 

containing breathing-quality air for 

human use. 

(vii) Ensure that vessels attendant to 

facilities carry appropriate protectivebreathing equipment for each crew 

member. The District Manager may require additional protective-breathing 

equipment on certain vessels attendant 

to the facility. 

(viii) During H2S alerts, limit helicopter flights to and from facilities to 

the conditions specified in the H2S Contingency Plan. During authorized 

flights, the flight crew and passengers 

must use pressure-demand-type respirators. You must train all members 

of flight crews in the use of the particular type(s) of respirator equipment 

made available. 

(ix) As appropriate to the particular 

operation(s), (production, drilling, 

well-completion or well-workover operations, or any combination of them), 

provide a system of breathing-air 

manifolds, hoses, and masks at the facility and the briefing areas. You must 

provide a cascade air-bottle system for 

the breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle 


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§ 250.490 30 CFR Ch. II (7–1–13 Edition) 

system may be recharged by a highpressure compressor suitable for providing breathing-quality air, provided 

the compressor suction is located in an 

uncontaminated atmosphere. 

(k) Personnel safety equipment: (1) 

What additional personnel-safety 

equipment do I need? You must ensure 

that your facility has: 

(i) Portable H2S detectors capable of 

detecting a 10 ppm concentration of 

H2S in the air available for use by all 

personnel; 

(ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas; 

(iii) Chalkboards and/or note pads for 

communication purposes located on 

the rig floor, shale-shaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas 

compressor area, and pipeline-pump 

area; 

(iv) Bull horns and flashing lights; 

and 

(v) At least three resuscitators on 

manned facilities, and a number equal 

to the personnel on board, not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and spare oxygen bottles. 

(2) What are the requirements for ventilation equipment? You must: 

(i) Use only explosion-proof ventilation devices; 

(ii) Install ventilation devices in 

areas where H2S or SO2 may accumulate; and 

(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H2S or 

SO2 vapors away from working personnel. 

(3) What other personnel safety equipment do I need? You must have the following equipment readily available on 

each facility: 

(i) A first-aid kit of appropriate size 

and content for the number of personnel on the facility; and 

(ii) At least one litter or an equivalent device. 

(l) Do I need to notify BSEE in the 

event of an H2S release? You must notify 

BSEE without delay in the event of a 

gas release which results in a 15- 

minute time-weighted average atmospheric concentration of H2S of 20 ppm 

or more anywhere on the OCS facility. 

You must report these gas releases to 

the District Manager immediately by 

oral communication, with a written 

follow-up report within 15 days, pursuant to §§250.188 through 250.190. 

(m) Do I need to use special drilling, 

completion and workover fluids or procedures? When working in an area classified as H2S present or H2S unknown: 

(1) You may use either water- or oilbase 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 waterbase well-control fluids in sufficient 

quantities to maintain pH of at least 

10.0. 

(iii) Corrosion inhibitors. You must 

add additives to the well-control fluid 

system as needed for the control of corrosion. 

(5) You must degas well-control 

fluids containing H2S at the optimum 

location for the particular facility. You 

must collect the gases removed and 

burn them in a closed flare system conforming to paragraph (q)(6) of this section. 

(n) What must I do in the event of a 

kick? In the event of a kick, you must 

use one of the following alternatives to 

dispose of the well-influx fluids giving 

consideration to personnel safety, possible environmental damage, and possible facility well-equipment damage: 


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(1) Contain the well-fluid influx by 

shutting in the well and pumping the 

fluids back into the formation. 

(2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in an open 

hole within the pressure limits of the 

well equipment (drill pipe, work string, 

casing, wellhead, BOP system, and related equipment). The disposal of H2S 

and other gases must be through pressurized or atmospheric mud-separator 

equipment depending on volume, pressure and concentration of H2S. The 

equipment must be designed to recover 

well-control fluids and burn the gases 

separated from the well-control fluid. 

The well-control fluid must be treated 

to neutralize H2S and restore and 

maintain the proper quality. 

(o) Well testing in a zone known to contain H2S. When testing a well in a zone 

with H2S present, you must do all of 

the following: 

(1) Before starting a well test, conduct safety meetings for all personnel 

who will be on the facility during the 

test. At the meetings, emphasize the 

use of protective-breathing equipment, 

first-aid procedures, and the Contingency Plan. Only competent personnel 

who are trained and are knowledgeable 

of the hazardous effects of H2S must be 

engaged in these tests. 

(2) Perform well testing with the 

minimum number of personnel in the 

immediate vicinity of the rig floor and 

with the appropriate test equipment to 

safely and adequately perform the test. 

During the test, you must continuously 

monitor H2S levels. 

(3) Not burn produced gases except 

through a flare which meets the requirements of paragraph (q)(6) of this 

section. Before flaring gas containing 

H2S, you must activate SO2 monitoring 

equipment in accordance with paragraph (j)(11) of this section. If you detect SO2 in excess of 2 ppm, you must 

implement the personnel protective 

measures in your H2S Contingency 

Plan, required by paragraph (f) of this 

section. You must also follow the requirements of §250.1164. You must pipe 

gases from stored test fluids into the 

flare outlet and burn them. 

(4) Use downhole test tools and wellhead equipment suitable for H2S service. 

(5) Use tubulars suitable for H2S service. You must not use drill pipe for well 

testing without the prior approval of 

the District Manager. Water cushions 

must be thoroughly inhibited in order 

to prevent H2S attack on metals. You 

must flush the test string fluid treated 

for this purpose after completion of the 

test. 

(6) Use surface test units and related 

equipment that is designed for H2S 

service. 

(p) Metallurgical properties of equipment. When operating in a zone with 

H2S present, you must use equipment 

that is constructed of materials with 

metallurgical properties that resist or 

prevent sulfide stress cracking (also 

known as hydrogen embrittlement, 

stress corrosion cracking, or H2S embrittlement), chloride-stress cracking, 

hydrogen-induced cracking, and other 

failure modes. You must do all of the 

following: 

(1) Use tubulars and other equipment, 

casing, tubing, drill pipe, couplings, 

flanges, and related equipment that is 

designed for H2S service. 

(2) Use BOP system components, 

wellhead, pressure-control equipment, 

and related equipment exposed to H2Sbearing fluids in conformance with 

NACE Standard MR0175–03 (as specified 

in §250.198). 

(3) Use temporary downhole well-security devices such as retrievable 

packers and bridge plugs that are designed for H2S service. 

(4) When producing in zones bearing 

H2S, use equipment constructed of materials capable of resisting or preventing sulfide stress cracking. 

(5) Keep the use of welding to a minimum during the installation or modification of a production facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking. 

(q) General requirements when operating in an H2S zone: (1) Coring operations. When you conduct coring operations in H2S-bearing zones, all personnel in the working area must wear 

protective-breathing equipment at 

least 10 stands in advance of retrieving 

the core barrel. Cores to be transported 

must be sealed and marked for the 

presence of H2S. 


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§ 250.500 30 CFR Ch. II (7–1–13 Edition) 

(2) Logging operations. You must treat 

and condition well-control fluid in use 

for logging operations to minimize the 

effects of H2S on the logging equipment. 

(3) Stripping operations. Personnel 

must monitor displaced well-control 

fluid returns and wear protectivebreathing equipment in the working 

area when the atmospheric concentration of H2S reaches 20 ppm or if the 

well is under pressure. 

(4) Gas-cut well-control fluid or well 

kick from H2S-bearing zone. If you decide 

to circulate out a kick, personnel in 

the working area during bottoms-up 

and extended-kill operations must wear 

protective-breathing equipment. 

(5) Drill- and workover-string design 

and precautions. Drill- and workoverstrings must be designed consistent 

with the anticipated depth, conditions 

of the hole, and reservoir environment 

to be encountered. You must minimize 

exposure of the drill- or workoverstring to high stresses as much as practical and consistent with well conditions. Proper handling techniques must 

be taken to minimize notching and 

stress concentrations. Precautions 

must be taken to minimize stresses 

caused by doglegs, improper stiffness 

ratios, improper torque, whip, abrasive 

wear on tool joints, and joint imbalance. 

(6) Flare system. The flare outlet must 

be of a diameter that allows easy nonrestricted flow of gas. You must locate 

flare line outlets on the downside of 

the facility and as far from the facility 

as is feasible, taking into account the 

prevailing wind directions, the wake 

effects caused by the facility and adjacent structure(s), and the height of all 

such facilities and structures. You 

must equip the flare outlet with an 

automatic ignition system including a 

pilot-light gas source or an equivalent 

system. You must have alternate 

methods for igniting the flare. You 

must pipe to the flare system used for 

H2S all vents from production process 

equipment, tanks, relief valves, burst 

plates, and similar devices. 

(7) Corrosion mitigation. You must use 

effective means of monitoring and controlling corrosion caused by acid gases 

(H2S and CO2) in both the downhole and 

surface portions of a production system. You must take specific corrosion 

monitoring and mitigating measures in 

areas of unusually severe corrosion 

where accumulation of water and/or 

higher concentration of H2S exists. 

(8) Wireline lubricators. Lubricators 

which may be exposed to fluids containing H2S must be of H2S-resistant 

materials. 

(9) Fuel and/or instrument gas. You 

must not use gas containing H2S for instrument gas. You must not use gas 

containing H2S for fuel gas without the 

prior approval of the District Manager. 

(10) Sensing lines and devices. Metals 

used for sensing line and safety-control 

devices which are necessarily exposed 

to H2S-bearing fluids must be constructed of H2S-corrosion resistant materials or coated so as to resist H2S 

corrosion. 

(11) Elastomer seals. You must use 

H2S-resistant materials for all seals 

which may be exposed to fluids containing H2S. 

(12) Water disposal. If you dispose of 

produced water by means other than 

subsurface injection, you must submit 

to the District Manager an analysis of 

the anticipated H2S content of the 

water at the final treatment vessel and 

at the discharge point. The District 

Manager may require that the water be 

treated for removal of H2S. The District Manager may require the submittal of an updated analysis if the 

water disposal rate or the potential 

H2S content increases. 

(13) Deck drains. You must equip open 

deck drains with traps or similar devices to prevent the escape of H2S gas 

into the atmosphere. 

(14) Sealed voids. You must take precautions to eliminate sealed spaces in 

piping designs (e.g., slip-on flanges, reinforcing pads) which can be invaded 

by atomic hydrogen when H2S is 

present. 

Subpart E—Oil and Gas WellCompletion Operations 

§ 250.500 General requirements. 

Well-completion operations shall be 

conducted in a manner to protect 

against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas 


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leased and not leased), the National security or defense, or the marine, coastal, or human environment. 

§ 250.501 Definition. 

When used in this subpart, the following term shall have the meaning 

given below: 

Well-completion operations means the 

work conducted to establish the production of a well after the productioncasing string has been set, cemented, 

and pressure-tested. 

§ 250.502 Equipment movement. 

The movement of well-completion 

rigs and related equipment on and off a 

platform or from well to well on the 

same platform, including rigging up 

and rigging down, shall be conducted in 

a safe manner. All wells in the same 

well-bay which are capable of producing hydrocarbons shall be shut in 

below the surface with a pumpthrough-type tubing plug and at the 

surface with a closed master valve 

prior to moving well-completion rigs 

and related equipment, unless otherwise approved by the District Manager. 

A closed surface-controlled subsurface 

safety valve of the pump-through type 

may be used in lieu of the pumpthrough-type tubing plug, provided 

that the surface control has been 

locked out of operation. The well from 

which the rig or related equipment is 

to be moved shall also be equipped with 

a back-pressure valve prior to removing the blowout preventer (BOP) system and installing the tree. 

§ 250.503 Emergency shutdown system. 

When well-completion operations are 

conducted on a platform where there 

are other hydrocarbon-producing wells 

or other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller’s console or 

well-servicing unit operator’s work station. 

§ 250.504 Hydrogen sulfide. 

When a well-completion operation is 

conducted in zones known to contain 

hydrogen sulfide (H2S) or in zones 

where the presence of H2S is unknown 

(as defined in §250.490 of this part), the 

lessee shall take appropriate precautions to protect life and property on 

the platform or completion unit, including, but not limited to operations 

such as blowing the well down, dismantling wellhead equipment and flow 

lines, circulating the well, swabbing, 

and pulling tubing, pumps, and packers. The lessee shall comply with the 

requirements in §250.490 of this part as 

well as the appropriate requirements of 

this subpart. 

§ 250.505 Subsea completions. 

No subsea well completion shall be 

commenced until the lessee obtains 

written approval from the District 

Manager in accordance with §250.513 of 

this part. That approval shall be based 

upon a case-by-case determination that 

the proposed equipment and procedures 

will adequately control the well and 

permit safe production operations. 

§ 250.506 Crew instructions. 

Prior to engaging in well-completion 

operations, crew members shall be instructed in the safety requirements of 

the operations to be performed, possible hazards to be encountered, and 

general safety considerations to protect personnel, equipment, and the environment. Date and time of safety 

meetings shall be recorded and available at the facility for review by BSEE 

representatives. 

§§ 250.507–250.508 [Reserved] 

§ 250.509 Well-completion structures 

on fixed platforms. 

Derricks, masts, substructures, and 

related equipment shall be selected, designed, installed, used, and maintained 

so as to be adequate for the potential 

loads and conditions of loading that 

may be encountered during the proposed operations. Prior to moving a 

well-completion rig or equipment onto 

a platform, the lessee shall determine 

the structural capability of the platform to safely support the equipment 

and proposed operations, taking into 

consideration the corrosion protection, 

age of platform, and previous stresses 

to the platform. 

§ 250.510 Diesel engine air intakes. 

Diesel engine air intakes must be 

equipped with a device to shut down 


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§ 250.511 30 CFR Ch. II (7–1–13 Edition) 

the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with 

either remote operated manual or 

automatic-shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic-shutdown devices. 

§ 250.511 Traveling-block safety device. 

All units being used for well-completion operations that have both a traveling block and a crown block must be 

equipped with a safety device that is 

designed to prevent the traveling block 

from striking the crown block. The device must be checked for proper operation weekly and after each drill-line 

slipping operation. The results of the 

operational check must be entered in 

the operations log. 

§ 250.512 Field well-completion rules. 

When geological and engineering information available in a field enables 

the District Manager to determine specific operating requirements, field 

well-completion rules may be established on the District Manager’s initiative or in response to a request from a 

lessee. Such rules may modify the specific requirements of this subpart. 

After field well-completion rules have 

been established, well-completion operations in the field shall be conducted in 

accordance with such rules and other 

requirements of this subpart. Field 

well-completion rules may be amended 

or canceled for cause at any time upon 

the initiative of the District Manager 

or upon the request of a lessee. 

§ 250.513 Approval and reporting of 

well-completion operations. 

(a) No well-completion operation 

may begin until the lessee receives 

written approval from the District 

Manager. If completion is planned and 

the data are available at the time you 

submit the Application for Permit to 

Drill and Supplemental APD Information Sheet (Forms BSEE–0123 and 

BSEE–0123S), you may request approval for a well-completion on those 

forms (see §§250.410 through 250.418 of 

this part). If the District Manager has 

not approved the completion or if the 

completion objective or plans have significantly changed, you must submit 

an Application for Permit to Modify 

(Form BSEE–0124) for approval of such 

operations. 

(b) You must submit the following 

with Form BSEE–0124 (or with Form 

BSEE–0123; Form BSEE–0123S): 

(1) A brief description of the wellcompletion procedures to be followed, a 

statement of the expected surface pressure, and type and weight of completion fluids; 

(2) A schematic drawing of the well 

showing the proposed producing zone(s) 

and the subsurface well-completion 

equipment to be used; 

(3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not 

been previously submitted; 

(4) All applicable information required in §250.515. 

(5) When the well-completion is in a 

zone known to contain H2S or a zone 

where the presence of H2S is unknown, 

information pursuant to §250.490 of this 

part; and 

(6) Payment of the service fee listed 

in §250.125. 

(c) Within 30 days after completion, 

you must submit to the District Manager an End of Operations Report 

(Form BSEE–0125), including a schematic of the tubing and subsurface 

equipment. 

(d) You must submit public information copies of Form BSEE–0125 according to §250.186. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50894, Aug. 22, 2012] 

§ 250.514 Well-control fluids, equipment, and operations. 

(a) Well-control fluids, equipment, 

and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The 

well shall be continuously monitored 

during well-completion operations and 

shall not be left unattended at any 

time unless the well is shut in and secured. 

(b) The following well-control-fluid 

equipment shall be installed, maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP; 


ehiers on DSK2VPTVN1PROD with CFR
121 

Safety & Environmental Enforcement, Interior § 250.515 

(2) A well-control, fluid-volume 

measuring device for determining fluid 

volumes when filling the hole on trips; 

and 

(3) A recording mud-pit-level indicator to determine mud-pit-volume 

gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

(c) When coming out of the hole with 

drill pipe, the annulus shall be filled 

with well-control fluid before the 

change in such fluid level decreases the 

hydrostatic pressure 75 pounds per 

square inch (psi) or every five stands of 

drill pipe, whichever gives a lower decrease in hydrostatic pressure. The 

number of stands of drill pipe and drill 

collars that may be pulled prior to filling the hole and the equivalent wellcontrol fluid volume shall be calculated and posted near the operator’s 

station. A mechanical, volumetric, or 

electronic device for measuring the 

amount of well-control fluid required 

to fill the hole shall be utilized. 

(d) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APM your reasons 

for displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The stepby-step displacement procedures must 

address the following: 

(1) Number and type of independent 

barriers, as described in §250.420(b)(3), 

that are in place for each flow path 

that requires such barriers, 

(2) Tests you will conduct to ensure 

integrity of independent barriers, 

(3) BOP procedures you will use while 

displacing kill-weight fluids, and 

(4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50894, Aug. 22, 2012] 

§ 250.515 What BOP information must 

I submit? 

For completion operations, your 

APM must include the following BOP 

descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) A schematic drawing of the BOP 

system that shows the inside diameter 

of the BOP stack, number and type of 

preventers, all control systems and 

pods, location of choke and kill lines, 

and associated valves; 

(c) Independent third-party 

verification and supporting documentation that show the blind-shear 

rams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole 

under maximum anticipated surface 

pressure. The documentation must include actual shearing and subsequent 

pressure integrity test results for the 

most rigid pipe to be used, and calculations of shearing capacity of all pipe to 

be used in the well including correction 

for maximum anticipated surface pressure; 

(d) When you use a subsea BOP stack, 

independent third-party verification 

that shows: 

(1) The BOP stack is designed for the 

specific equipment on the rig and for 

the specific well design; 

(2) The BOP stack has not been compromised or damaged from previous 

service; 

(3) The BOP stack will operate in the 

conditions in which it will be used; and 

(e) The qualifications of the independent third-party referenced in paragraphs (c) and (d) of this section: 

(1) The independent third-party in 

this section must be a technical classification society, or a licensed professional engineering firm, or a registered 

professional engineer capable of providing the verifications required under 

this part. 

(2) You must: 

(i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm you are using or its employees hold appropriate licenses to 

perform the verification in the appropriate jurisdiction, and evidence to 

demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the required verifications; and 

(ii) Ensure that an official representative of BSEE will have access to the 


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§ 250.516 30 CFR Ch. II (7–1–13 Edition) 

location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must notify the BSEE District Manager at 

least 72 hours in advance. 

[77 FR 50894, Aug. 22, 2012] 

§ 250.516 Blowout prevention equipment. 

(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The 

working pressure rating of the BOP 

system and BOP system components 

shall exceed the expected surface pressure to which they may be subjected. If 

the expected surface pressure exceeds 

the rated working pressure of the annular preventer, the lessee shall submit 

with Form BSEE–0124 or Form BSEE– 

0123, as appropriate, a well-control procedure that indicates how the annular 

preventer will be utilized, and the pressure limitations that will be applied 

during each mode of pressure control. 

(b) The minimum BOP system for 

well-completion operations must meet 

the appropriate standards from the following table: 

When . . . The minimum BOP stack must include . . . 

(1) The expected pressure is less than 5,000 psi, Three BOPs consisting of an annular, one set of pipe rams, 

and one set of blind-shear rams. 

(2) The expected pressure is 5,000 psi or greater or you use 

multiple tubing strings, 

Four BOPs consisting of an annular, two sets of pipe rams, 

and one set of blind-shear rams. 

(3) You handle multiple tubing strings simultaneously, Four BOPs consisting of an annular, one set of pipe rams, one 

set of dual pipe rams, and one set of blind-shear rams. 

(4) You use a tapered drill string, At least one set of pipe rams that are capable of sealing 

around each size of drill string. If the expected pressure is 

greater than 5,000 psi, then you must have at least two sets 

of pipe rams that are capable of sealing around the larger 

size drill string. You may substitute one set of variable bore 

rams for two sets of pipe rams. 

(5) You use a subsea BOP stack, The requirements in § 250.442(a) of this part. 

(c) The BOP systems for well completions must be equipped with the following: 

(1) A hydraulic-actuating system 

that provides sufficient accumulator 

capacity to supply 1.5 times the volume 

necessary to close all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure without assistance from a charging system. 

Accumulator regulators supplied by rig 

air and without a secondary source of 

pneumatic supply, must be equipped 

with manual overrides, or alternately, 

other devices provided to ensure capability of hydraulic operations if rig air 

is lost. 

(2) A secondary power source, independent from the primary power 

source, with sufficient capacity to 

close all BOP system components and 

hold them closed. 

(3) Locking devices for the pipe-ram 

preventers. 

(4) At least one remote BOP-control 

station and one BOP-control station on 

the rig floor. 

(5) A choke line and a kill line each 

equipped with two full opening valves 

and a choke manifold. At least one of 

the valves on the choke line shall be 

remotely controlled. At least one of 

the valves on the kill line shall be remotely controlled, except that a check 

valve on the kill line in lieu of the remotely controlled valve may be installed provided that two readily accessible manual valves are in place and 

the check valve is placed between the 

manual valves and the pump. This 

equipment shall have a pressure rating 

at least equivalent to the ram preventers. 

(d) An inside BOP or a spring-loaded, 

back-pressure safety valve and an essentially full-opening, work-string 

safety valve in the open position shall 

be maintained on the rig floor at all 

times during well-completion operations. A wrench to fit the work-string 

safety valve shall be readily available. 

Proper connections shall be readily 

available for inserting valves in the 

work string. 


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Safety & Environmental Enforcement, Interior § 250.517 

(e) The subsea BOP system for wellcompletions must meet the requirements in §250.442 of this part. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.517 Blowout preventer system 

tests, inspections, and maintenance. 

(a) BOP pressure testing timeframes. 

You must pressure test your BOP system: 

(1) When installed; and 

(2) Before 14 days have elapsed since 

your last BOP pressure test. You must 

begin to test your BOP system before 

12 a.m. (midnight) on the 14th day following the conclusion of the previous 

test. However, the District Manager 

may require testing every 7 days if conditions or BOP performance warrant. 

(b) BOP test pressures. When you test 

the BOP system, you must conduct a 

low pressure and a high pressure test 

for each BOP component. Each individual pressure test must hold pressure 

long enough to demonstrate that the 

tested component(s) holds the required 

pressure. The District Manager may 

approve or require other test pressures 

or practices. Required test pressures 

are as follows: 

(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to 

a pressure between 200 and 300 psi before starting the test. If the initial 

pressure exceeds 500 psi, you must 

bleed back to zero and reinitiate the 

test. You must conduct the low pressure test before the high pressure test. 

(2) For ram-type BOP’s, choke manifold, and other BOP equipment, the 

high pressure test must equal the rated 

working pressure of the equipment. 

(3) For annular-type BOP’s, the high 

pressure test must equal 70 percent of 

the rated working pressure of the 

equipment. 

(c) Duration of pressure test. Each test 

must hold the required pressure for 5 

minutes. 

(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour 

chart, on a 1-hour chart, or on a digital 

recorder. 

(2) If the equipment does not hold the 

required pressure during a test, you 

must remedy the problem and retest 

the affected component(s). 

(d) Additional BOP testing requirements. You must: 

(1) Use water to test the surface BOP 

system; 

(2) Stump test a subsea BOP system 

before installation. You must use 

water to conduct this test. You may 

use drilling or completion fluids to 

conduct subsequent tests of a subsea 

BOP system. You must perform the initial subsea BOP test on the seafloor 

within 30 days of the stump test. 

(3) Alternate tests between control 

stations and pods. If a control station 

or pod is not functional, you must suspend further completion operations 

until that station or pod is operable; 

(4) Pressure test the blind or blindshear ram at least every 30 days; 

(5) Function test annulars and rams 

every 7 days; 

(6) Pressure-test variable bore-pipe 

rams against all sizes of pipe in use, excluding drill collars and bottom-hole 

tools; 

(7) Test affected BOP components following the disconnection or repair of 

any well-pressure containment seal in 

the wellhead or BOP stack assembly; 

(8) Test all ROV intervention functions on your subsea BOP stack during 

the stump test. Each ROV must be 

fully compatible with the BOP stack 

ROV intervention panels. You must 

also test and verify closure of at least 

one set of rams during the initial test 

on the seafloor through an ROV hot 

stab. You must submit test procedures, 

including how you will test each ROV 

function, with your APM for BSEE District Manager approval. You must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of actuating, at a minimum, one set of pipe 

rams, one set of blind-shear rams, and 

unlatching the LMRP; 

(ii) Notify the appropriate BSEE District Manager a minimum of 72 hours 

prior to the stump test and initial test 

on the seafloor; 

(iii) Document all your test results 

and make them available to BSEE 

upon request; and 

(9) Function test autoshear and 

deadman systems on your subsea BOP 


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§ 250.517 30 CFR Ch. II (7–1–13 Edition) 

stack during the stump test. You must 

also test the deadman system and 

verify closure of at least one set of 

blind-shear rams during the initial test 

on the seafloor. When you conduct the 

initial deadman system test on the 

seafloor you must ensure the well is secure and, if hydrocarbons have been 

present, appropriate barriers are in 

place to isolate hydrocarbons from the 

wellhead. You must also have an ROV 

on bottom during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager approval. The procedures for these function tests must include documentation 

of the controls and circuitry of the system utilized during each test. The procedure must also describe how the ROV 

will be utilized during this operation. 

(ii) Document all your test results 

and make them available to BSEE 

upon request. 

(e) Postponing BOP tests. You may 

postpone a BOP test if you have wellcontrol problems. You must conduct 

the required BOP test as soon as possible (i.e., first trip out of the hole) 

after the problem has been remedied. 

You must record the reason for postponing any test in the driller’s report. 

(f) Weekly crew drills. You must conduct a weekly drill to familiarize all 

personnel engaged in well-completion 

operations with appropriate safety 

measures. 

(g) BOP inspections. (1) You must inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells (incorporated by reference as specified in §250.198). You 

must document how you met or exceeded the provisions of Sections 17.10 and 

18.10 described in API RP 53, the procedures used, record the results, and 

make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

(2) You must visually inspect your 

surface BOP system on a daily basis. 

You must visually inspect your subsea 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use television cameras to inspect subsea equipment. The BSEE District Manager may 

approve alternate methods and frequencies to inspect a marine riser. 

(h) BOP maintenance. You must maintain your BOP system to ensure that 

the equipment functions properly. The 

BOP maintenance must meet or exceed 

the provisions of Sections 17.11 and 

18.11, Maintenance; and Sections 17.12 

and 18.12, Quality Management, described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(incorporated by reference as specified 

in §250.198). You must document how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

the procedures used, record the results, 

and make the records available to 

BSEE upon request. You must maintain your records on the rig for 2 years 

from the date the records are created, 

or for a longer period if directed by 

BSEE. 

(i) BOP test records. You must record 

the time, date, and results of all pressure tests, actuations, crew drills, and 

inspections of the BOP system, system 

components, and marine riser in the 

driller’s report. In addition, you must: 

(1) Record BOP test pressures on 

pressure charts; 

(2) Have your onsite representative 

certify (sign and date) BOP test charts 

and reports as correct; 

(3) Document the sequential order of 

BOP and auxiliary equipment testing 

and the pressure and duration of each 

test. You may reference a BOP test 

plan if it is available at the facility; 

(4) Identify the control station or pod 

used during the test; 

(5) Identify any problems or irregularities observed during BOP system 

and equipment testing and record actions taken to remedy the problems or 

irregularities; 

(6) 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 the 

completion activity; and 


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Safety & Environmental Enforcement, Interior § 250.520 

(7) After completion of the well, you 

must retain all the records listed in 

paragraph (i)(6) of this section for a period of 2 years at the facility, at the 

lessee’s field office nearest the OCS facility, or at another location conveniently available to the District Manager. 

(j) Alternate methods. The District 

Manager may require, or approve, more 

frequent testing, as well as different 

test pressures and inspection methods, 

or other practices. 

[76 FR 64462, Oct. 18, 2011. Redesignated and 

amended at 77 FR 50894, 50895, Aug. 22, 2012] 

§ 250.518 Tubing and wellhead equipment. 

(a) No tubing string shall be placed in 

service or continue to be used unless 

such tubing string has the necessary 

strength and pressure integrity and is 

otherwise suitable for its intended use. 

(b) In the event of prolonged operations such as milling, fishing, jarring, 

or washing over that could damage the 

casing, the casing shall be pressuretested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Manager. 

(c) When the tree is installed, you 

must equip wells to monitor for casing 

pressure according to the following 

chart: 

If you . . . you must equip . . . so you can monitor . . . 

(1) fixed platform wells, the wellhead, all annuli (A, B, C, D, etc., annuli). 

(2) subsea wells, the tubing head, the production casing annulus (A annulus). 

(3) hybrid * wells, the surface wellhead, all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the production casing 

riser above the mudline are pressure isolated from each 

other, provisions must be made to monitor the production 

casing below the mudline for casing pressure. 

* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a 

surface tubing hanger, and a surface christmas tree. 

(d) Wellhead, tree, and related equipment shall have a pressure rating 

greater than the shut-in tubing pressure and shall be designed, installed, 

used, maintained, and tested so as to 

achieve and maintain pressure control. 

New wells completed as flowing or gaslift wells shall be equipped with a minimum of one master valve and one surface safety valve, installed above the 

master valve, in the vertical run of the 

tree. 

(e) Subsurface safety equipment shall 

be installed, maintained, and tested in 

compliance with §250.801 of this part. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

CASING PRESSURE MANAGEMENT

§ 250.519 What are the requirements 

for casing pressure management? 

Once you install your wellhead, you 

must meet the casing pressure management requirements of API RP 90 (as incorporated by reference in §250.198) and 

the requirements of §§250.519 through 

250.530. If there is a conflict between 

API RP 90 and the casing pressure requirements of this subpart, you must 

follow the requirements of this subpart. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.520 How often do I have to monitor for casing pressure? 

You must monitor for casing pressure in your well according to the following table: 

If you have . . . you must monitor . . . with a minimum one pressure data point recorded per . . . 

(a) fixed platform wells, monthly, month for each casing. 

(b) subsea wells, continuously, day for the production casing. 

(c) hybrid wells, continuously, day for each riser and/or the production casing. 

(d) wells operating under a casing pressure request on a manned fixed platform, daily, day for each casing. 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.521 30 CFR Ch. II (7–1–13 Edition) 

If you have . . . you must monitor . . . with a minimum one pressure data point recorded per . . . 

(e) wells operating under a casing pressure request on an unmanned fixed platform, weekly, week for each casing. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012] 

§ 250.521 When do I have to perform a 

casing diagnostic test? 

(a) You must perform a casing diagnostic test within 30 days after first observing or imposing casing pressure according to the following table: 

If you have a . . . you must perform a casing diagnostic test if . . . 

(1) fixed platform well, the casing pressure is greater than 100 psig. 

(2) subsea well, the measurable casing pressure is greater than the external 

hydrostatic pressure plus 100 psig measured at the subsea 

wellhead. 

(3) hybrid well, a riser or the production casing pressure is greater than 100 

psig measured at the surface. 

(b) You are exempt from performing 

a diagnostic pressure test for the production casing on a well operating 

under active gas lift. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.522 How do I manage the thermal 

effects caused by initial production 

on a newly completed or recompleted well? 

A newly completed or recompleted 

well often has thermal casing pressure 

during initial startup. Bleeding casing 

pressure during the startup process is 

considered a normal and necessary operation to manage thermal casing pressure; therefore, you do not need to 

evaluate these operations as a casing 

diagnostic test. After 30 days of continuous production, the initial production 

startup operation is complete and you 

must perform casing diagnostic testing 

as required in §§250.520 and 250.522. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.523 When do I have to repeat casing diagnostic testing? 

Casing diagnostic testing must be repeated according to the following 

table: 

When . . . you must repeat diagnostic testing . . . 

(a) your casing pressure request approved term has expired, immediately. 

(b) your well, previously on gas lift, has been shut-in or returned to flowing status without gas lift for more than 180 

days, 

immediately on the production casing (A annulus). The production casing (A annulus) of wells on active gas lift are exempt 

from diagnostic testing. 

(c) your casing pressure request becomes invalid, within 30 days. 

(d) a casing or riser has an increase in pressure greater than 

200 psig over the previous casing diagnostic test, 

within 30 days. 

(e) after any corrective action has been taken to remediate undesirable casing pressure, either as a result of a casing 

pressure request denial or any other action, 

within 30 days. 

(f) your fixed platform well production casing (A annulus) has 

pressure exceeding 10 percent of its minimum internal yield 

pressure (MIYP), except for production casings on active gas 

lift, 

once per year, not to exceed 12 months between tests. 

(g) your fixed platform well’s outer casing (B, C, D, etc., annuli) 

has a pressure exceeding 20 percent of its MIYP, 

once every 5 years, at a minimum. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012] 


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Safety & Environmental Enforcement, Interior § 250.528 

§ 250.524 How long do I keep records 

of casing pressure and diagnostic 

tests? 

Records of casing pressure and diagnostic tests must be kept at the field 

office nearest the well for a minimum 

of 2 years. The last casing diagnostic 

test for each casing or riser must be retained at the field office nearest the 

well until the well is abandoned. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.525 When am I required to take 

action from my casing diagnostic 

test? 

You must take action if you have 

any of the following conditions: 

(a) Any fixed platform well with a 

casing pressure exceeding its maximum 

allowable wellhead operating pressure 

(MAWOP); 

(b) Any fixed platform well with a 

casing pressure that is greater than 100 

psig and that cannot bleed to 0 psig 

through a 1⁄2-inch needle valve within 

24 hours, or is not bled to 0 psig during 

a casing diagnostic test; 

(c) Any well that has demonstrated 

tubing/casing, tubing/riser, casing/casing, riser/casing, or riser/riser communication; 

(d) Any well that has sustained casing pressure (SCP) and is bled down to 

prevent it from exceeding its MAWOP, 

except during initial startup operations described in §250.521; 

(e) Any hybrid well with casing or 

riser pressure exceeding 100 psig; or 

(f) Any subsea well with a casing 

pressure 100 psig greater than the external hydrostatic pressure at the 

subsea wellhead. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.526 What do I submit if my casing diagnostic test requires action? 

Within 14 days after you perform a 

casing diagnostic test requiring action 

under §250.524: 

You must submit either 

. . . to the appropriate . . . and it must include . . . You must also . . . 

(a) a notification of corrective action; or, District Manager and 

copy the Regional 

Supervisor, Field Operations, 

requirements under 

§ 250.526, 

submit an Application for Permit to Modify or 

Corrective Action Plan within 30 days of the 

diagnostic test. 

(b) a casing pressure request, Regional Supervisor, 

Field Operations, 

requirements under 

§ 250.527. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 FR 50894, Aug. 22, 2012] 

§ 250.527 What must I include in my 

notification of corrective action? 

The following information must be 

included in the notification of corrective action: 

(a) Lessee or Operator name; 

(b) Area name and OCS block number; 

(c) Well name and API number; and 

(d) Casing diagnostic test data. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.528 What must I include in my 

casing pressure request? 

The following information must be 

included in the casing pressure request: 

(a) API number; 

(b) Lease number; 

(c) Area name and OCS block number; 

(d) Well number; 

(e) Company name and mailing address; 

(f) All casing, riser, and tubing sizes, 

weights, grades, and MIYP; 

(g) All casing/riser calculated 

MAWOPs; 

(h) All casing/riser pre-bleed down 

pressures; 

(i) Shut-in tubing pressure; 

(j) Flowing tubing pressure; 

(k) Date and the calculated daily production rate during last well test (oil, 

gas, basic sediment, and water); 

(l) Well status (shut-in, temporarily 

abandoned, producing, injecting, or gas 

lift); 

(m) Well type (dry tree, hybrid, or 

subsea); 


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§ 250.529 30 CFR Ch. II (7–1–13 Edition) 

(n) Date of diagnostic test; 

(o) Well schematic; 

(p) Water depth; 

(q) Volumes and types of fluid bled 

from each casing or riser evaluated; 

(r) Type of diagnostic test performed: 

(1) Bleed down/buildup test; 

(2) Shut-in the well and monitor the 

pressure drop test; 

(3) Constant production rate and decrease the annular pressure test; 

(4) Constant production rate and increase the annular pressure test; 

(5) Change the production rate and 

monitor the casing pressure test; and 

(6) Casing pressure and tubing pressure history plot; 

(s) The casing diagnostic test data 

for all casing exceeding 100 psig; 

(t) Associated shoe strengths for casing shoes exposed to annular fluids; 

(u) Concentration of any H2S that 

may be present; 

(v) Whether the structure on which 

the well is located is manned or unmanned; 

(w) Additional comments; and 

(x) Request date. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.529 What are the terms of my 

casing pressure request? 

Casing pressure requests are approved by the Regional Supervisor, 

Field Operations, for a term to be determined by the Regional Supervisor 

on a case-by-case basis. The Regional 

Supervisor may impose additional restrictions or requirements to allow 

continued operation of the well. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.530 What if my casing pressure 

request is denied? 

(a) If your casing pressure request is 

denied, then the operating company 

must submit plans for corrective action to the respective District Manager 

within 30 days of receiving the denial. 

The District Manager will establish a 

specific time period in which this corrective action will be taken. You must 

notify the respective District Manager 

within 30 days after completion of your 

corrected action. 

(b) You must submit the casing diagnostic test data to the appropriate Regional Supervisor, Field Operations, 

within 14 days of completion of the diagnostic test required under §250.522(e). 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

§ 250.531 When does my casing pressure request approval become invalid? 

A casing pressure request becomes 

invalid when: 

(a) The casing or riser pressure increases by 200 psig over the approved 

casing pressure request pressure; 

(b) The approved term ends; 

(c) The well is worked-over, sidetracked, redrilled, recompleted, or acid 

stimulated; 

(d) A different casing or riser on the 

same well requires a casing pressure request; or 

(e) A well has more than one casing 

operating under a casing pressure request and one of the casing pressure requests become invalid, then all casing 

pressure requests for that well become 

invalid. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50894, Aug. 22, 2012] 

Subpart F—Oil and Gas WellWorkover Operations 

§ 250.600 General requirements. 

Well-workover operations shall be 

conducted in a manner to protect 

against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer 

Continental Shelf (OCS) including any 

mineral deposits (in areas leased and 

not leased), the National security or 

defense, or the marine, coastal, or 

human environment. 

§ 250.601 Definitions. 

When used in this subpart, the following terms shall have the meanings 

given below: 

Expected surface pressure means the 

highest pressure predicted to be exerted upon the surface of a well. In calculating expected surface pressure, you 

must consider reservoir pressure as 

well as applied surface pressure. 

Routine operations mean any of the 

following operations conducted on a 

well with the tree installed: 


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Safety & Environmental Enforcement, Interior § 250.606 

(a) Cutting paraffin; 

(b) Removing and setting pumpthrough-type tubing plugs, gas-lift 

valves, and subsurface safety valves 

which can be removed by wireline operations; 

(c) Bailing sand; 

(d) Pressure surveys; 

(e) Swabbing; 

(f) Scale or corrosion treatment; 

(g) Caliper and gauge surveys; 

(h) Corrosion inhibitor treatment; 

(i) Removing or replacing subsurface 

pumps; 

(j) Through-tubing logging 

(diagnostics); 

(k) Wireline fishing; and 

(l) Setting and retrieving other subsurface flow-control devices. 

Workover operations mean the work 

conducted on wells after the initial 

completion for the purpose of maintaining or restoring the productivity of 

a well. 

§ 250.602 Equipment movement. 

The movement of well-workover rigs 

and related equipment on and off a 

platform or from well to well on the 

same platform, including rigging up 

and rigging down, shall be conducted in 

a safe manner. All wells in the same 

well-bay which are capable of producing hydrocarbons shall be shut in 

below the surface with a pumpthrough-type tubing plug and at the 

surface with a closed master valve 

prior to moving well-workover rigs and 

related equipment unless otherwise approved by the District Manager. A 

closed surface-controlled subsurface 

safety valve of the pump-through-type 

may be used in lieu of the pumpthrough-type tubing plug provided that 

the surface control has been locked out 

of operation. The well to which a wellworkover rig or related equipment is to 

be moved shall also be equipped with a 

back-pressure valve prior to removing 

the tree and installing and testing the 

blowout-preventer (BOP) system. The 

well from which a well-workover rig or 

related equipment is to be moved shall 

also be equipped with a back pressure 

valve prior to removing the BOP system and installing the tree. Coiled tubing units, snubbing units, or wireline 

units may be moved onto a platform 

without shutting in wells. 

§ 250.603 Emergency shutdown system. 

When well-workover operations are 

conducted on a well with the tree removed, an emergency shutdown system 

(ESD) manually controlled station 

shall be installed near the driller’s console or well-servicing unit operator’s 

work station, except when there is no 

other hydrocarbon-producing well or 

other hydrocarbon flow on the platform. 

§ 250.604 Hydrogen sulfide. 

When a well-workover operation is 

conducted in zones known to contain 

hydrogen sulfide (H2S) or in zones 

where the presence of H2S is unknown 

(as defined in §250.490 of this part), the 

lessee shall take appropriate precautions to protect life and property on 

the platform or rig, including but not 

limited to operations such as blowing 

the well down, dismantling wellhead 

equipment and flow lines, circulating 

the well, swabbing, and pulling tubing, 

pumps and packers. The lessee shall 

comply with the requirements in 

§250.490 of this part as well as the appropriate requirements of this subpart. 

§ 250.605 Subsea workovers. 

No subsea well-workover operation 

including routine operations shall be 

commenced until the lessee obtains 

written approval from the District 

Manager in accordance with §250.613 of 

this part. That approval shall be based 

upon a case-by-case determination that 

the proposed equipment and procedures 

will maintain adequate control of the 

well and permit continued safe production operations. 

§ 250.606 Crew instructions. 

Prior to engaging in well-workover 

operations, crew members shall be instructed in the safety requirements of 

the operations to be performed, possible hazards to be encountered, and 

general safety considerations to protect personnel, equipment, and the environment. Date and time of safety 

meetings shall be recorded and available at the facility for review by a 

BSEE representative. 


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§§ 250.607–250.608 30 CFR Ch. II (7–1–13 Edition) 

§§ 250.607–250.608 [Reserved] 

§ 250.609 Well-workover structures on 

fixed platforms. 

Derricks, masts, substructures, and 

related equipment shall be selected, designed, installed, used, and maintained 

so as to be adequate for the potential 

loads and conditions of loading that 

may be encountered during the operations proposed. Prior to moving a 

well-workover rig or well-servicing 

equipment onto a platform, the lessee 

shall determine the structural capability of the platform to safely support 

the equipment and proposed operations, taking into consideration the 

corrosion protection, age of the platform, and previous stresses to the platform. 

§ 250.610 Diesel engine air intakes. 

No later than May 31, 1989, diesel engine air intakes shall be equipped with 

a device to shut down the diesel engine 

in the event of runaway. Diesel engines 

which are continuously attended shall 

be equipped with either remote operated manual or automatic shutdown 

devices. Diesel engines which are not 

continuously attended shall be 

equipped with automatic shutdown devices. 

§ 250.611 Traveling-block safety device. 

After May 31, 1989, all units being 

used for well-workover operations 

which have both a traveling block and 

a crown block shall be equipped with a 

safety device which is designed to prevent the traveling block from striking 

the crown block. The device shall be 

checked for proper operation weekly 

and after each drill-line slipping operation. The results of the operational 

check shall be entered in the operations log. 

§ 250.612 Field well-workover rules. 

When geological and engineering information available in a field enables 

the District Manager to determine specific operating requirements, field 

well-workover rules may be established 

on the District Manager’s initiative or 

in response to a request from a lessee. 

Such rules may modify the specific requirements of this subpart. After field 

well-workover rules have been established, well-workover operations in the 

field shall be conducted in accordance 

with such rules and other requirements 

of this subpart. Field well-workover 

rules may be amended or canceled for 

cause at any time upon the initiative 

of the District Manager or upon the request of a lessee. 

§ 250.613 Approval and reporting for 

well-workover operations. 

(a) No well-workover operation except routine ones, as defined in §250.601 

of this part, shall begin until the lessee 

receives written approval from the District Manager. Approval for these operations must be requested on Form 

BSEE–0124, Application for Permit to 

Modify. 

(b) You must submit the following 

with Form BSEE–0124: 

(1) A brief description of the wellworkover procedures to be followed, a 

statement of the expected surface pressure, and type and weight of workover 

fluids; 

(2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the 

zone proposed for workover and the 

workover equipment to be used; 

(3) All information required in 

§250.615. 

(4) Where the well-workover is in a 

zone known to contain H2S or a zone 

where the presence of H2S is unknown, 

information pursuant to §250.490 of this 

part; and 

(5) Payment of the service fee listed 

in §250.125. 

(c) The following additional information shall be submitted with Form 

BSEE–0124 if completing to a new zone 

is proposed: 

(1) Reason for abandonment of 

present producing zone including supportive well test data, and 

(2) A statement of anticipated or 

known pressure data for the new zone. 

(d) Within 30 days after completing 

the well-workover operation, except 

routine operations, Form BSEE–0124, 

Application for Permit to Modify, shall 

be submitted to the District Manager, 

showing the work as performed. In the 

case of a well-workover operation resulting in the initial recompletion of a 

well into a new zone, a Form BSEE– 


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Safety & Environmental Enforcement, Interior § 250.615 

0125, End of Operations Report, shall be 

submitted to the District Manager and 

shall include a new schematic of the 

tubing subsurface equipment if any 

subsurface equipment has been 

changed. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50895, Aug. 22, 2012] 

§ 250.614 Well-control fluids, equipment, and operations. 

The following requirements apply 

during all well-workover operations 

with the tree removed: 

(a) Well-control fluids, equipment, 

and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The 

well shall be continuously monitored 

during well-workover operations and 

shall not be left unattended at anytime 

unless the well is shut in and secured. 

(b) When coming out of the hole with 

drill pipe or a workover string, the annulus shall be filled with well-control 

fluid before the change in such fluid 

level decreases the hydrostatic pressure 75 pounds per square inch (psi) or 

every five stands of drill pipe or 

workover string, whichever gives a 

lower decrease in hydrostatic pressure. 

The number of stands of drill pipe or 

workover string and drill collars that 

may be pulled prior to filling the hole 

and the equivalent well-control fluid 

volume shall be calculated and posted 

near the operator’s station. A mechanical, volumetric, or electronic device 

for measuring the amount of well-control fluid required to fill the hold shall 

be utilized. 

(c) The following well-control-fluid 

equipment shall be installed, maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP; 

(2) A well-control, fluid-volume 

measuring device for determining fluid 

volumes when filling the hole on trips; 

and 

(3) A recording mud-pit-level indicator to determine mud-pit-volume 

gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

(d) Before you displace kill-weight 

fluid from the wellbore and/or riser to 

an underbalanced state, you must obtain approval from the BSEE District 

Manager. To obtain approval, you must 

submit with your APM your reasons 

for displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The stepby-step displacement procedures must 

address the following: 

(1) Number and type of independent 

barriers, as described in §250.420(b)(3), 

that are in place for each flow path 

that requires such barriers, 

(2) Tests you will conduct to ensure 

integrity of independent barriers, 

(3) BOP procedures you will use while 

displacing kill weight fluids, and 

(4) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50895, Aug. 22, 2012] 

§ 250.615 What BOP information must 

I submit? 

For well-workover operations, your 

APM must include the following BOP 

descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) A schematic drawing of the BOP 

system that shows the inside diameter 

of the BOP stack, number and type of 

preventers, all control systems and 

pods, location of choke and kill lines, 

and associated valves; 

(c) Independent third-party 

verification and supporting documentation that show the blind-shear 

rams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole 

under maximum anticipated surface 

pressure. The documentation must include actual shearing and subsequent 

pressure integrity test results for the 

most rigid pipe to be used and calculations of shearing capacity of all pipe to 

be used in the well, including correction for under maximum anticipated 

surface pressure; 

(d) When you use a subsea BOP stack, 

independent third-party verification 

that shows: 


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132 

§ 250.616 30 CFR Ch. II (7–1–13 Edition) 

(1) The BOP stack is designed for the 

specific equipment on the rig and for 

the specific well design; 

(2) The BOP stack has not been compromised or damaged from previous 

service; 

(3) The BOP stack will operate in the 

conditions in which it will be used; and 

(e) The qualifications of the independent third-party referenced in paragraphs (c) and (d) of this section: 

(1) The independent third-party in 

this section must be a technical classification society, or a licensed professional engineering firm, or a registered 

professional engineer capable of providing the verifications required under 

this part. 

(2) You must: 

(i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm you are using or its employees hold appropriate licenses to 

perform the verification in the appropriate jurisdiction, and evidence to 

demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the required verifications. 

(ii) Ensure that an official representative of BSEE will have access to the 

location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must notify the BSEE District Manager at 

least 72 hours in advance. 

[77 FR 50895, Aug. 22, 2012] 

§ 250.616 Blowout prevention equipment. 

(a) The BOP system, system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The 

working pressure rating of the BOP 

system and system components shall 

exceed the expected surface pressure to 

which they may be subjected. If the expected surface pressure exceeds the 

rated working pressure of the annular 

preventer, the lessee shall submit with 

Form BSEE–0124, requesting approval 

of the well-workover operation, a wellcontrol procedure that indicates how 

the annular preventer will be utilized, 

and the pressure limitations that will 

be applied during each mode of pressure control. 

(b) The minimum BOP system for 

well-workover operations with the tree 

removed must meet the appropriate 

standards from the following table: 

When . . . The minimum BOP stack must include . . . 

(1) The expected pressure is less than 5,000 psi, Three BOPs consisting of an annular, one set of pipe rams, 

and one set of blind-shear rams. 

(2) The expected pressure is 5,000 psi or greater or you use 

multiple tubing strings, 

Four BOPs consisting of an annular, two sets of pipe rams, 

and one set of blind-shear rams. 

(3) You handle multiple tubing strings simultaneously, Four BOPs consisting of an annular, one set of pipe rams, one 

set of dual pipe rams, and one set of blind-shear rams. 

(4) You use a tapered drill string, At least one set of pipe rams that are capable of sealing 

around each size of drill string. If the expected pressure is 

greater than 5,000 psi, then you must have at least two sets 

of pipe rams that are capable of sealing around the larger 

size drill string. You may substitute one set of variable bore 

rams for two sets of pipe rams. 

(5) You use a subsea BOP stack, The requirements in § 250.442(a) of this part. 

(c) The BOP systems for wellworkover operations with the tree removed must be equipped with the following: 

(1) A hydraulic-actuating system 

that provides sufficient accumulator 

capacity to supply 1.5 times the volume 

necessary to close all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure without assistance from a charging system. 

Accumulator regulators supplied by rig 

air and without a secondary source of 

pneumatic supply, must be equipped 

with manual overrides, or alternately, 

other devices provided to ensure capability of hydraulic operations if rig air 

is lost; 

(2) A secondary power source, independent from the primary power 


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Safety & Environmental Enforcement, Interior § 250.616 

source, with sufficient capacity to 

close all BOP system components and 

hold them closed; 

(3) Locking devices for the pipe-ram 

preventers; 

(4) At least one remote BOP-control 

station and one BOP-control station on 

the rig floor; and 

(5) A choke line and a kill line each 

equipped with two full opening valves 

and a choke manifold. At least one of 

the valves on the choke-line shall be 

remotely controlled. At least one of 

the valves on the kill line shall be remotely controlled, except that a check 

valve on the kill line in lieu of the remotely controlled valve may be installed provided two readily accessible 

manual valves are in place and the 

check valve is placed between the manual valves and the pump. This equipment shall have a pressure rating at 

least equivalent to the ram preventers. 

(d) The minimum BOP-system components for well-workover operations 

with the tree in place and performed 

through the wellhead inside of conventional tubing using small-diameter 

jointed pipe (usually 3⁄4 inch to 11⁄4

inch) as a work string, i.e., small-tubing operations, shall include the following: 

(1) Two sets of pipe rams, and 

(2) One set of blind rams. 

(e) The subsea BOP system for wellworkover operations must meet the requirements in §250.442 of this part. 

(f) For coiled tubing operations with 

the production tree in place, you must 

meet the following minimum requirements for the BOP system: 

(1) BOP system components must be 

in the following order from the top 

down: 

BOP system when expected 

surface pressures are less than or equal 

to 3,500 psi 

BOP system when expected 

surface pressures are greater than 3,500 

psi 

BOP system for wells with returns taken 

through an outlet on the BOP stack 

Stripper or annular-type well control component.Stripper or annular-type well control 

component.

Stripper or annular-type well control 

component. 

Hydraulically-operated blind rams ............. Hydraulically-operated blind rams ........... Hydraulically-operated blind rams 

Hydraulically-operated shear rams ............ Hydraulically-operated shear rams ......... Hydraulically-operated shear rams. 

Kill line inlet ............................................... Kill line inlet ............................................. Kill line inlet. 

Hydraulically-operated two-way slip rams Hydraulically-operated two-way slip rams Hydraulically-operated two-way slip 

rams. 

Hydraulically-operated pipe rams. 

Hydraulically-operated pipe rams .............. Hydraulically-operated pipe rams ............

Hydraulically-operated blind-shear rams. 

These rams should be located as 

close to the tree as practical.

A flow tee or cross. 

Hydraulically-operated pipe rams. 

Hydraulically-operated blind-shear rams 

on wells with surface pressures > 

3,500 psi. As an option, the pipe rams 

can be placed below the blind-shear 

rams. The blind-shear rams should be 

located as close to the tree as practical. 

(2) You may use a set of hydraulically-operated combination rams for 

the blind rams and shear rams. 

(3) You may use a set of hydraulically-operated combination rams for 

the hydraulic two-way slip rams and 

the hydraulically-operated pipe rams. 

(4) You must attach a dual check 

valve assembly to the coiled tubing 

connector at the downhole end of the 

coiled tubing string for all coiled tubing well-workover operations. If you 

plan to conduct operations without 

downhole check valves, you must describe alternate procedures and equipment in Form BSEE–0124, Application 

for Permit to Modify and have it approved by the District Manager. 

(5) You must have a kill line and a 

separate choke line. You must equip 

each line with two full-opening valves 

and at least one of the valves must be 

remotely controlled. You may use a 

manual valve instead of the remotely 

controlled valve on the kill line if you 

install a check valve between the two 

full-opening manual valves and the 

pump or manifold. The valves must 

have a working pressure rating equal 

to or greater than the working pressure rating of the connection to which 

they are attached, and you must install them between the well control 


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§ 250.617 30 CFR Ch. II (7–1–13 Edition) 

stack and the choke or kill line. For 

operations with expected surface pressures greater than 3,500 psi, the kill 

line must be connected to a pump or 

manifold. You must not use the kill 

line inlet on the BOP stack for taking 

fluid returns from the wellbore. 

(6) You must have a hydraulic-actuating system that provides sufficient 

accumulator capacity to close-openclose each component in the BOP 

stack. This cycle must be completed 

with at least 200 psi above the precharge pressure, without assistance 

from a charging system. 

(7) All connections used in the surface BOP system from the tree to the 

uppermost required ram must be 

flanged, including the connections between the well control stack and the 

first full-opening valve on the choke 

line and the kill line. 

(g) The minimum BOP-system components for well-workover operations 

with the tree in place and performed by 

moving tubing or drill pipe in or out of 

a well under pressure utilizing equipment specifically designed for that purpose, i.e., snubbing operations, shall include the following: 

(1) One set of pipe rams hydraulically 

operated, and 

(2) Two sets of stripper-type pipe 

rams hydraulically operated with spacer spool. 

(h) An inside BOP or a spring-loaded, 

back-pressure safety valve and an essentially full-opening, work-string 

safety valve in the open position shall 

be maintained on the rig floor at all 

times during well-workover operations 

when the tree is removed or during 

well-workover operations with the tree 

installed and using small tubing as the 

work string. A wrench to fit the workstring safety valve shall be readily 

available. Proper connections shall be 

readily available for inserting valves in 

the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50895, Aug. 22, 2012] 

§ 250.617 Blowout preventer system 

testing, records, and drills. 

(a) BOP pressure tests. When you pressure test the BOP system you must 

conduct a low-pressure test and a highpressure test for each component. You 

must conduct the low-pressure test before the high-pressure test. For purposes of this section, BOP system components include ram-type BOP’s, related control equipment, choke and 

kill lines, and valves, manifolds, strippers, and safety valves. Surface BOP 

systems must be pressure tested with 

water. 

(1) Low pressure tests. All BOP system 

components must be successfully tested to a low pressure between 200 and 300 

psi. Any initial pressure equal to or 

greater than 300 psi must be bled back 

to a pressure between 200 and 300 psi 

before starting the test. If the initial 

pressure exceeds 500 psi, you must 

bleed back to zero before starting the 

test. 

(2) High pressure tests. All BOP system 

components must be successfully tested to the rated working pressure of the 

BOP equipment, or as otherwise approved by the District Manager. The 

annular-type BOP must be successfully 

tested at 70 percent of its rated working pressure or as otherwise approved 

by the District Manager. 

(3) Other testing requirements. Variable 

bore pipe rams must be pressure tested 

against the largest and smallest sizes 

of tubulars in use (jointed pipe, seamless pipe) in the well. 

(b) Times. The BOP systems shall be 

tested at the following times: 

(1) When installed; 

(2) At least every 7 days, alternating 

between control stations and at staggered intervals to allow each crew to 

operate the equipment. If either control system is not functional, further 

operations shall be suspended until the 

nonfunctional, system is operable. The 

test every 7 days is not required for 

blind or blind-shear rams. The blind or 

blind-shear rams shall be tested at 

least once every 30 days during operation. A longer period between blowout 

preventer tests is allowed when there is 

a stuck pipe or pressure-control operation and remedial efforts are being 

performed. The tests shall be conducted as soon as possible and before 

normal operations resume. The reason 

for postponing testing shall be entered 

into the operations log. 


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Safety & Environmental Enforcement, Interior § 250.617 

(3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure tested. 

(c) Drills. All personnel engaged in 

well-workover operations shall participate in a weekly BOP drill to familiarize crew members with appropriate 

safety measures. 

(d) Stump tests. You may conduct a 

stump test for the BOP system on location. A plan describing the stump test 

procedures must be included in your 

Form BSEE–0124, Application for Permit to Modify, and must be approved 

by the District Manager. 

(e) Coiled tubing tests. You must test 

the coiled tubing connector to a low 

pressure of 200 to 300 psi, followed by a 

high pressure test to the rated working 

pressure of the connector or the expected surface pressure, whichever is 

less. You must successfully pressure 

test the dual check valves to the rated 

working pressure of the connector, the 

rated working pressure of the dual 

check valve, expected surface pressure, 

or the collapse pressure of the coiled 

tubing, whichever is less. 

(f) Recordings. You must record test 

pressures during BOP and coiled tubing 

tests on a pressure chart, or with a digital recorder, unless otherwise approved by the District Manager. The 

test interval for each BOP system component must be 5 minutes, except for 

coiled tubing operations, which must 

include a 10 minute high-pressure test 

for the coiled tubing string. Your representative at the facility must certify 

that the charts are correct. 

(g) Operations log. The time, date, and 

results of all pressure tests, actuations, 

inspections, and crew drills of the BOP 

system, system components, and marine risers shall be recorded in the operations log. The BOP tests shall be 

documented in accordance with the following: 

(1) The documentation shall indicate 

the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an 

alternate, the documentation in the 

operations log may reference a BOP 

test plan that contains the required information and is retained on file at the 

facility. 

(2) The control station used during 

the test shall be identified in the operations log. For a subsea system, the 

pod used during the test shall be identified in the operations log. 

(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to 

remedy such problems or irregularities 

shall be noted in the operations log. 

(4) Documentation required to be entered in the operation log may instead 

be referenced in the operations log. All 

records including pressure charts, operations log, and referenced documents 

pertaining to BOP tests, actuations, 

and inspections, shall be available for 

BSEE review at the facility for the duration of well-workover activity. Following completion of the wellworkover activity, all such records 

shall be retained for a period of 2 years 

at the facility, at the lessee’s filed office nearest the OCS facility, or at another location conveniently available 

to the District Manager. 

(h) Stump test a subsea BOP system 

before installation. You must use 

water to conduct this test. You may 

use drilling or completion fluids to 

conduct subsequent tests of a subsea 

BOP system. You must perform the initial subsea BOP test on the seafloor 

within 30 days of the stump test. You 

must: 

(1) Test all ROV intervention functions on your subsea BOP stack during 

the stump test. Each ROV must be 

fully compatible with the BOP stack 

ROV intervention panels. You must 

also test and verify closure of at least 

one set of rams during the initial test 

on the seafloor through an ROV hot 

stab. You must submit test procedures, 

including how you will test each ROV 

function, with your APM for BSEE District Manager approval. You must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of actuating, at a minimum, one set of pipe 

rams, one set of blind-shear rams, and 

unlatching the LMRP; 

(ii) Notify the appropriate BSEE District Manager a minimum of 72 hours 

prior to the stump test and initial test 

on the seafloor; 

(iii) Document all your test results 

and make them available to BSEE 

upon request; and 


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§ 250.618 30 CFR Ch. II (7–1–13 Edition) 

(2) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system and 

verify closure of at least one set of 

blind-shear rams during the initial test 

on the seafloor. When you conduct the 

initial deadman system test on the 

seafloor you must ensure the well is secure and, if hydrocarbons have been 

present, appropriate barriers are in 

place to isolate hydrocarbons from the 

wellhead. You must also have an ROV 

on bottom during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager approval. The procedures for these function tests must include documentation 

of the controls and circuitry of the system utilized during each test. The procedure must also describe how the ROV 

will be utilized during this operation. 

(ii) Document the results of each test 

and make them available to BSEE 

upon request. 

[76 FR 64462, Oct. 18, 2011. Redesignated and 

amended at 77 FR 50895, 50896, Aug. 22, 2012] 

§ 250.618 What are my BOP inspection 

and maintenance requirements? 

(a) BOP inspections. (1) You must inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells (incorporated by reference as specified in §250.198). You 

must document how you met or exceeded the provisions of Sections 17.10 and 

18.10 described in API RP 53, the procedures used, record the results, and 

make the records available to BSEE 

upon request. You must maintain your 

records on the rig for 2 years from the 

date the records are created, or for a 

longer period if directed by BSEE. 

(2) You must visually inspect your 

surface BOP system on a daily basis. 

You must visually inspect your subsea 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use television cameras to inspect subsea equipment. The BSEE District Manager may 

approve alternate methods and frequencies to inspect a marine riser. 

(b) BOP maintenance. You must maintain your BOP system to ensure that 

the equipment functions properly. The 

BOP maintenance must meet or exceed 

the provisions of Sections 17.11 and 

18.11, Maintenance; and Sections 17.12 

and 18.12, Quality Management, described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(incorporated by reference as specified 

in §250.198). You must document how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

the procedures used, record the results, 

and make the records available to 

BSEE upon request. You must maintain your records on the rig for 2 years 

from the date the records are created, 

or for a longer period if directed by 

BSEE. 

[77 FR 50896, Aug. 22, 2012] 

§ 250.619 Tubing and wellhead equipment. 

The lessee shall comply with the following requirements during wellworkover operations with the tree removed: 

(a) No tubing string shall be placed in 

service or continue to be used unless 

such tubing string has the necessary 

strength and pressure integrity and is 

otherwise suitable for its intended use. 

(b) In the event of prolonged operations such as milling, fishing, jarring, 

or washing over that could damage the 

casing, the casing shall be pressure 

tested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Manager. 

(c) When reinstalling the tree, you 

must: 

(1) Equip wells to monitor for casing 

pressure according to the following 

chart: 

If you have . . . you must equip . . . so you can monitor . . . 

(i) fixed platform wells, the wellhead, all annuli (A, B, C, D, etc., annuli). 

(ii) subsea wells, the tubing head, the production casing annulus (A annulus). 


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Safety & Environmental Enforcement, Interior § 250.801 

If you have . . . you must equip . . . so you can monitor . . . 

(iii) hybrid* wells, the surface wellhead, all annuli at the surface (A and B riser annuli). If the production casing below the mudline and the production casing 

riser above the mudline are pressure isolated from each 

other, provisions must be made to monitor the production 

casing below the mudline for casing pressure. 

* Characterized as a well drilled with a subsea wellhead and completed with a surface casing head, a surface tubing head, a 

surface tubing hanger, and a surface christmas tree. 

(2) Follow the casing pressure management requirements in subpart E of 

this part. 

(d) Wellhead, tree, and related equipment shall have a pressure rating 

greater than the shut-in tubing pressure and shall be designed, installed, 

used, maintained, and tested so as to 

achieve and maintain pressure control. 

The tree shall be equipped with a minimum of one master valve and one surface safety valve in the vertical run of 

the tree when it is reinstalled. 

(e) Subsurface safety equipment shall 

be installed, maintained, and tested in 

compliance with §250.801 of this part. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50895, Aug. 22, 2012] 

§ 250.620 Wireline operations. 

The lessee shall comply with the following requirements during routine, as 

defined in §250.601 of this part, and 

nonroutine wireline workover operations: 

(a) Wireline operations shall be conducted so as to minimize leakage of 

well fluids. Any leakage that does 

occur shall be contained to prevent pollution. 

(b) All wireline perforating operations and all other wireline operations 

where communication exists between 

the completed hydrocarbon-bearing 

zone(s) and the wellbore shall use a lubricator assembly containing at least 

one wireline valve. 

(c) When the lubricator is initially 

installed on the well, it shall be successfully pressure tested to the expected shut-in surface pressure. 

[76 FR 64462, Oct. 18, 2011. Redesignated at 77 

FR 50895, Aug. 22, 2012] 

Subpart G [Reserved] 

Subpart H—Oil and Gas 

Production Safety Systems 

§ 250.800 General requirements. 

(a) Production safety equipment 

shall be designed, installed, used, 

maintained, and tested in a manner to 

assure the safety and protection of the 

human, marine, and coastal environments. Production safety systems operated in subfreezing climates shall utilize equipment and procedures selected 

with consideration of floating ice, 

icing, and other extreme environmental conditions that may occur in 

the area. Production shall not commence until the production safety system has been approved and a 

preproduction inspection has been requested by the lessee. 

(b) For all new floating production 

systems (FPSs) (e.g., column-stabilized-units (CSUs); floating production, storage and offloading facilities 

(FPSOs); tension-leg platforms (TLPs); 

spars, etc.), you must do all of the following: 

(1) Comply with API RP 14J (as incorporated by reference in 30 CFR 

250.198); 

(2) Meet the drilling and production 

riser standards of API RP 2RD (as incorporated by reference in 30 CFR 

250.198); 

(3) Design all stationkeeping systems 

for floating facilities to meet the 

standards of API RP 2SK (as incorporated by reference in 30 CFR 250.198), 

as well as relevant U.S. Coast Guard 

regulations; and 

(4) Design stationkeeping systems for 

floating facilities to meet structural 

requirements in subpart I, §§250.900 

through 250.921 of this part. 

§ 250.801 Subsurface safety devices. 

(a) General. All tubing installations 

open to hydrocarbon-bearing zones 


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§ 250.801 30 CFR Ch. II (7–1–13 Edition) 

shall be equipped with subsurface safety devices that will shut off the flow 

from the well in the event of an emergency unless, after application and justification, the well is determined by 

the District Manager to be incapable of 

natural flowing. These devices may 

consist of a surface-controlled subsurface safety valve (SSSV), a subsurface-controlled SSSV, an injection 

valve, a tubing plug, or a tubing/annular subsurface safety device, and any 

associated safety valve lock or landing 

nipple. 

(b) Specifications for SSSVs. Surfacecontrolled and subsurface-controlled 

SSSVs and safety valve locks and landing nipples installed in the OCS shall 

conform to the requirements in §250.806 

of this part. 

(c) Surface-controlled SSSVs. All tubing installations open to a hydrocarbon-bearing zone which is capable of 

natural flow shall be equipped with a 

surface-controlled SSSV, except as 

specified in paragraphs (d), (f), and (g) 

of this section. The surface controls 

may be located on the site or a remote 

location. Wells not previously equipped 

with a surface-controlled SSSV and 

wells in which a surface-controlled 

SSSV has been replaced with a subsurface-controlled SSSV in accordance 

with paragraph (d)(2) of this section 

shall be equipped with a surface-controlled SSSV when the tubing is first 

removed and reinstalled. 

(d) Subsurface-controlled SSSVs. Wells 

may be equipped with subsurface-controlled SSSVs in lieu of a surface-controlled SSSV provided the lessee demonstrates to the District Manager’s 

satisfaction that one of the following 

criteria are met: 

(1) Wells not previously equipped 

with surface-controlled SSSVs shall be 

so equipped when the tubing is first removed and reinstalled, 

(2) The subsurface-controlled SSSV is 

installed in wells completed from a single-well or multiwell satellite caisson 

or seafloor completions, or 

(3) The subsurface-controlled SSSV is 

installed in wells with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing. 

(e) Design, installation, and operation 

of SSSVs. The SSSVs shall be designed, 

installed, operated, and maintained to 

ensure reliable operation. 

(1) The device shall be installed at a 

depth of 100 feet or more below the 

seafloor within 2 days after production 

is established. When warranted by conditions such as permafrost, unstable 

bottom conditions, hydrate formation, 

or paraffins, an alternate setting depth 

of the subsurface safety device may be 

approved by the District Manager. 

(2) Until a subsurface safety device is 

installed, the well shall be attended in 

the immediate vicinity so that emergency actions may be taken while the 

well is open to flow. During testing and 

inspection procedures, the well shall 

not be left unattended while open to 

production unless a properly operating 

subsurface-safety device has been installed in the well. 

(3) The well shall not be open to flow 

while the subsurface safety device is 

removed, except when flowing of the 

well is necessary for a particular operation such as cutting paraffin, bailing 

sand, or similar operations. 

(4) All SSSVs must be inspected, installed, maintained, and tested in accordance with American Petroleum Institute Recommended Practice 14B, 

Recommended Practice for Design, Installation, Repair, and Operation of 

Subsurface Safety Valve Systems (as 

specified in §250.198). 

(f) Subsurface safety devices in shut-in 

wells. (1) New completions (perforated 

but not placed on production) and completions shut in for a period of 6 

months shall be equipped with either— 

(i) A pump-through-type tubing plug; 

(ii) A surface-controlled SSSV, provided the surface control has been rendered inoperative; or 

(iii) An injection valve capable of 

preventing backflow. 

(2) The setting depth of the subsurface safety device shall be approved 

by the District Manager on a case-bycase basis, when warranted by conditions such as permafrost, unstable bottom conditions, hydrate formations, 

and paraffins. 

(g) Subsurface safety devices in injection wells. A surface-controlled SSSV or 

an injection valve capable of preventing backflow shall be installed in 

all injection wells. This requirement is 

not applicable if the District Manager 


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Safety & Environmental Enforcement, Interior § 250.802 

concurs that the well is incapable of 

flowing. The lessee shall verify the noflow condition of the well annually. 

(h) Temporary removal for routine operations. (1) Each wireline- or pumpdownretrievable subsurface safety device 

may be removed, without further authorization or notice, for a routine operation which does not require the approval of a Form BSEE–0124, Application for Permit to Modify, in §250.601 of 

this part for a period not to exceed 15 

days. 

(2) The well shall be identified by a 

sign on the wellhead stating that the 

subsurface safety device has been removed. The removal of the subsurface 

safety device shall be noted in the 

records as required in §250.804(b) of this 

part. If the master valve is open, a 

trained person shall be in the immediate vicinity of the well to attend the 

well so that emergency actions may be 

taken, if necessary. 

(3) A platform well shall be monitored, but a person need not remain in 

the well-bay area continuously if the 

master valve is closed. If the well is on 

a satellite structure, it must be attended or a pump-through plug installed in the tubing at least 100 feet 

below the mud line and the master 

valve closed, unless otherwise approved 

by the District Manager. 

(4) The well shall not be allowed to 

flow while the subsurface safety device 

is removed, except when flowing the 

well is necessary for that particular operation. The provisions of this paragraph are not applicable to the testing 

and inspection procedures in §250.804 of 

this part. 

(i) Additional safety equipment. All 

tubing installations in which a 

wireline- or pumpdown-retrievable subsurface safety device is installed after 

the effective date of this subpart shall 

be equipped with a landing nipple with 

flow couplings or other protective 

equipment above and below to provide 

for the setting of the SSSV. The control system for all surface-controlled 

SSSVs shall be an integral part of the 

platform Emergency Shutdown System 

(ESD). In addition to the activation of 

the ESD by manual action on the platform, the system may be activated by 

a signal from a remote location. Surface-controlled SSSVs shall close in response to shut-in signals from the ESD 

and in response to the fire loop or 

other fire detection devices. 

(j) Emergency action. In the event of 

an emergency, such as an impending 

storm, any well not equipped with a 

subsurface safety device and which is 

capable of natural flow shall have the 

device properly installed as soon as 

possible with due consideration being 

given to personnel safety. 

§ 250.802 Design, installation, and operation of surface production-safety 

systems. 

(a) General. All production facilities, 

including separators, treaters, compressors, headers, and flowlines shall 

be designed, installed, and maintained 

in a manner which provides for efficiency, safety of operation, and protection of the environment. 

(b) Platforms. You must protect all 

platform production facilities with a 

basic and ancillary surface safety system designed, analyzed, installed, tested, and maintained in operating condition in accordance with API RP 14C (as 

incorporated by reference in §250.198). 

If you use processing components other 

than those for which Safety Analysis 

Checklists are included in API RP 14C 

you must utilize the analysis technique 

and documentation specified therein to 

determine the effects and requirements 

of these components on the safety system. Safety device requirements for 

pipelines are under §250.1004. 

(c) Specification for surface safety 

valves (SSV) and underwater safety 

valves (USV). All wellhead SSVs, USVs, 

and their actuators which are installed 

in the OCS shall conform to the requirements in §250.806 of this part. 

(d) Use of SSVs and USV’s. All SSVs 

and USVs must be inspected, installed, 

maintained, and tested in accordance 

with API RP 14H, Recommended Practice for Installation, Maintenance, and 

Repair of Surface Safety Valves and 

Underwater Safety Valves Offshore (as 

incorporated by reference in §250.198). 

If any SSV or USV does not operate 

properly or if any fluid flow is observed 

during the leakage test, the valve shall 

be repaired or replaced. 


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§ 250.803 30 CFR Ch. II (7–1–13 Edition) 

(e) Approval of safety-systems design 

and installation features. Prior to installation, the lessee shall submit, in duplicate for approval to the District 

Manager a production safety system 

application containing information relative to design and installation features. Information concerning approved design and installation features 

shall be maintained by the lessee at 

the lessee’s offshore field office nearest 

the OCS facility or other location conveniently available to the District 

Manager. All approvals are subject to 

field verifications. The application 

shall include the following: 

(1) A schematic flow diagram showing tubing pressure, size, capacity, design working pressure of separators, 

flare scrubbers, treaters, storage tanks, 

compressors, pipeline pumps, metering 

devices, and other hydrocarbon-handling vessels. 

(2) A schematic piping flow diagram 

(API RP 14C, Figure E, as incorporated 

by reference in §250.198) and the related 

Safety analysis Function Evaluation 

chart (API RP 14C, subsection 4.3c, as 

incorporated by reference in §250.198). 

(3) A schematic piping diagram showing the size and maximum allowable 

working pressures as determined in accordance with API RP 14E, Design and 

Installation of Offshore Production 

Platform Piping Systems (as incorporated by reference in §250.198). 

(4) Electrical system information including the following: 

(i) A plan for each platform deck outlining all hazardous areas classified 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, or API RP 

505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities 

Classified as Class I, Zone 0, Zone 1, 

and Zone 2 (as incorporated by reference in §250.198), and outlining areas 

in which potential ignition sources, 

other than electrical, are to be installed. The area outlined will include 

the following information: 

(A) All major production equipment, 

wells, and other significant hydrocarbon sources and a description of the 

type of decking, ceiling, walls (e.g., 

grating or solid) and firewalls; and 

(B) Location of generators, control 

rooms, panel boards, major cabling/ 

conduit routes, and identification of 

the primary wiring method (e.g., type 

cable, conduit, or wire). 

(ii) Elementary electrical schematic 

of any platform safety shut-down system with a functional legend. 

(5) Certification that the design for 

the mechanical and electrical systems 

to be installed were approved by registered professional engineers. After 

these systems are installed, the lessee 

shall submit a statement to the District Manager certifying that new installations conform to the approved designs of this subpart. 

(6) The design and schematics of the 

installation and maintenance of all 

fire- and gas-detection systems shall 

include the following: 

(i) Type, location, and number of detection sensors; 

(ii) Type and kind of alarms, including emergency equipment to be activated; 

(iii) Method used for detection; 

(iv) Method and frequency of calibration; and 

(v) A functional block diagram of the 

detection system, including the electric power supply. 

(7) The service fee listed in §250.125. 

The fee you must pay will be determined by the number of components 

involved in the review and approval 

process. 

§ 250.803 Additional production system 

requirements. 

(a) For all production platforms, you 

must comply with the following production safety system requirements, in 

addition to the requirements of §250.802 

of this subpart and the requirements of 

API RP 14C (as incorporated by reference in §250.198). 

(b) Design, installation, and operation 

of additional production systems—(1) 

Pressure and fired vessels. Pressure 

and fired vessels must be designed, fabricated, and code stamped in accordance with the applicable provisions of 

Sections I, IV, and VIII of the American Society of Mechanical Engineers 

(ASME) Boiler and Pressure Vessel 

Code. Pressure and fired vessels must 


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Safety & Environmental Enforcement, Interior § 250.803 

have maintenance inspection, rating, 

repair, and alteration performed in accordance with the applicable provisions 

of API Pressure Vessel Inspections 

Code: In-Service Inspection, Rating, 

Repair, and Alteration, API 510 (except 

Sections 5.8 and 9.5) (as incorporated 

by reference in §250.198). 

(i) Pressure relief valves shall be designed, installed, and maintained in accordance with applicable provisions of 

sections I, IV, and VIII of the ASME 

Boiler and Pressure Vessel Code. The 

relief valves shall conform to the 

valve-sizing and pressure-relieving requirements specified in these documents; however, the relief valves, except completely redundant relief 

valves, shall be set no higher than the 

maximum-allowable working pressure 

of the vessel. All relief valves and vents 

shall be piped in such a way as to prevent fluid from striking personnel or 

ignition sources. 

(ii) Steam generators operating at 

less than 15 pounds per square inch 

gauge (psig) shall be equipped with a 

level safety low (LSL) sensor which 

will shut off the fuel supply when the 

water level drops below the minimum 

safe level. Steam generators operating 

at greater than 15 psig require, in addition to an LSL, a water-feeding device 

which will automatically control the 

water level. 

(iii) The lessee shall use pressure recorders to establish the new operating 

pressure ranges of pressure vessels at 

any time when there is a change in operating pressures that requires new 

settings for the high-pressure shut-in 

sensor and/or the low-pressure shut-in 

sensor as provided herein. The pressure-recorder charts used to determine 

current operating pressure ranges shall 

be maintained at the lessee’s field office nearest the OCS facility or at 

other locations conveniently available 

to the District Manager. The high-pressure shut-in sensor shall be set no 

higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below 

(5 percent or 5 psi, whichever is greater) the relief valve’s set pressure to assure that the pressure source is shut in 

before the relief valve activates. The 

low-pressure shut-in sensor shall activate no lower than 15 percent or 5 psi, 

whichever is greater, below the lowest 

pressure in the operating range. The 

activation of low-pressure sensors on 

pressure vessels which operate at less 

than 5 psi shall be approved by the District Manager on a case-by-case basis. 

(2) Flowlines. (i) You must equip 

flowlines from wells with high- and 

low-pressure shut-in sensors located in 

accordance with section A.1 and Figure 

A1 of API RP 14C (as incorporated by 

reference in §250.198). The lessee shall 

use pressure recorders to establish the 

new operating pressure ranges of 

flowlines at any time when there is a 

significant change in operating pressures. The most recent pressure-recorder charts used to determine operating pressure ranges shall be maintained at the lessee’s field office nearest the OCS facility or at other locations conveniently available to the District Manager. The high-pressure shutin sensor(s) shall be set no higher than 

15 percent or 5 psi, whichever is greater, above the highest operating pressure of the line. But in all cases, it 

shall be set sufficiently below the maximum shut-in wellhead pressure or the 

gas-lift supply pressure to assure actuation of the SSV. The low-pressure 

shut-in sensor(s) shall be set no lower 

than 15 percent or 5 psi, whichever is 

greater, below the lowest operating 

pressure of the line in which it is installed. 

(ii) If a well flows directly to the 

pipeline before separation, the flowline 

and valves from the well located upstream of and including the header 

inlet valve(s) shall have a working 

pressure equal to or greater than the 

maximum shut-in pressure of the well 

unless the flowline is protected by one 

of the following: 

(A) A relief valve which vents into 

the platform flare scrubber or some 

other location approved by the District 

Manager. The platform flare scrubber 

shall be designed to handle, without 

liquid-hydrocarbon carryover to the 

flare, the maximum-anticipated flow of 

liquid hydrocarbons which may be relieved to the vessel. 

(B) Two SSV’s with independent 

high-pressure sensors installed with 

adequate volume upstream of any 

block valve to allow sufficient time for 


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§ 250.803 30 CFR Ch. II (7–1–13 Edition) 

the valve(s) to close before exceeding 

the maximum allowable working pressure. 

(iii) If you are installing flowlines 

constructed of unbonded flexible pipe 

on a floating platform, you must: 

(A) Review the manufacturer’s Design Methodology Verification Report 

and the independent verification 

agent’s (IVA’s) certificate for the design methodology contained in that report to ensure that the manufacturer 

has complied with the requirements of 

API Spec 17J (as incorporated by reference in §250.198); 

(B) Determine that the unbonded 

flexible pipe is suitable for its intended 

purpose on the lease or pipeline rightof-way; 

(C) Submit to the BSEE District 

Manager the manufacturer’s design 

specifications for the unbonded flexible 

pipe; and 

(D) Submit to the BSEE District 

Manager a statement certifying that 

the pipe is suitable for its intended use 

and that the manufacturer has complied with the IVA requirements of API 

Spec 17J (as incorporated by reference 

in §250.198). 

(3) Safety sensors. All shutdown devices, valves, and pressure sensors shall 

function in a manual reset mode. Sensors with integral automatic reset 

shall be equipped with an appropriate 

device to override the automatic reset 

mode. All pressure sensors shall be 

equipped to permit testing with an external pressure source. 

(4) ESD. The ESD must conform to 

the requirements of Appendix C, section C1, of API RP 14C (as incorporated 

by reference in §250.198), and the following: 

(i) The manually operated ESD 

valve(s) shall be quick-opening and 

nonrestricted to enable the rapid actuation of the shutdown system. Only 

ESD stations at the boat landing may 

utilize a loop of breakable synthetic 

tubing in lieu of a valve. 

(ii) Closure of the SSV shall not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV shall close in not more 

than 2 minutes after the shut-in signal 

has closed the SSV. Design-delayed 

closure time greater than 2 minutes 

shall be justified by the lessee based on 

the individual well’s mechanical/production characteristics and be approved by the District Manager. 

(iii) A schematic of the ESD which 

indicates the control functions of all 

safety devices for the platforms shall 

be maintained by the lessee on the 

platform or at the lessee’s field office 

nearest the OCS facility or other location conveniently available to the District Manager. 

(5) Engines: (i) Engine exhaust. You 

must equip engine exhausts to comply 

with the insulation and personnel protection requirements of API RP 14C, 

section 4.2c(4) (as incorporated by reference in §250.198). Exhaust piping from 

diesel engines must be equipped with 

spark arresters. 

(ii) Diesel engine air intake. All diesel 

engine air intakes must be equipped 

with a device to shutdown the diesel 

engine in the event of runaway. Diesel 

engines that are continuously attended 

must be equipped with either remote 

operated manual or automatic shutdown devices. Diesel engines that are 

not continuously attended must be 

equipped with automatic shutdown devices. 

(6) Glycol dehydration units. A pressure relief system or an adequate vent 

shall be installed on the glycol regenerator (reboiler) which will prevent 

overpressurization. The discharge of 

the relief valve shall be vented in a 

nonhazardous manner. 

(7) Gas compressors. You must equip 

compressor installations with the following protective equipment as required in API RP 14C, Sections A4 and 

A8 (as incorporated by reference in 

§250.198). 

(i) A Pressure Safety High (PSH), a 

Pressure Safety Low (PSL), a Pressure 

Safety Valve (PSV), and a Level Safety 

High (LSH), and an LSL to protect 

each interstage and suction scrubber. 

(ii) A Temperature Safety High 

(TSH) on each compressor discharge 

cylinder. 

(iii) The PSH and PSL shut-in sensors and LSH shut-in controls protecting compressor suction and 

interstage scrubbers shall be designated to actuate automatic shutdown 

valves (SDV) located in each compressor suction and fuel gas line so 


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Safety & Environmental Enforcement, Interior § 250.803 

that the compressor unit and the associated vessels can be isolated from all 

input sources. All automatic SDV’s installed in compressor suction and fuel 

gas piping shall also be actuated by the 

shutdown of the prime mover. Unless 

otherwise approved by the District 

Manager, gas—well gas affected by the 

closure of the automatic SDV on a 

compressor suction shall be diverted to 

the pipeline or shut in at the wellhead. 

(iv) A blowdown valve is required on 

the discharge line of all compressor installations of 1,000 horsepower (746 

kilowatts) or greater. 

(8) Firefighting systems. Firefighting 

systems for both open and totally enclosed platforms installed for extreme 

weather conditions or other reasons 

shall conform to subsection 5.2, Firewater systems, of API RP 14G (as incorporated by reference in §250.198), 

Fire Prevention and Control Open Type 

Offshore Production Platforms, and 

shall require approval of the District 

Manager. The following additional requirements shall apply for both openand closed-production platforms: 

(i) A firewater system consisting of 

rigid pipe with firehose stations or 

fixed firewater monitors shall be installed. The firewater system shall be 

installed to provide needed protection 

in all areas where production-handling 

equipment is located. A fixed 

waterspray system shall be installed in 

enclosed well-bay areas where hydrocarbon vapors may accumulate. 

(ii) Fuel or power for firewater pump 

drivers shall be available for at least 30 

minutes of run time during a platform 

shut-in. If necessary, an alternate fuel 

or power supply shall be installed to 

provide for this pump-operating time 

unless an alternate firefighting system 

has been approved by the District Manager. 

(iii) A firefighting system using 

chemicals may be used in lieu of a 

water system if the District Manager 

determines that the use of a chemical 

system provides equivalent fire-protection control. 

(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a 

prominent place on the facility or 

structure. 

(v) For operations in subfreezing climates, the lessee shall furnish evidence 

to the District Manager that the firefighting system is suitable for the conditions. 

(9) Fire- and gas-detection system. (i) 

Fire (flame, heat, or smoke) sensors 

shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated, 

enclosed classified areas. Adequate 

ventilation is defined as ventilation 

which is sufficient to prevent accumulation of significant quantities of 

vapor-air mixture in concentrations 

over 25 percent of the lower explosive 

limit (LEL). One approved method of 

providing adequate ventilation is a 

change of air volume each 5 minutes or 

1 cubic foot of air-volume flow per 

minute per square foot of solid floor 

area, whichever is greater. Enclosed 

areas (e.g., buildings, living quarters, 

or doghouses) are defined as those 

areas confined on more than four of 

their six possible sides by walls, floors, 

or ceilings more restrictive to air flow 

than grating or fixed open louvers and 

of sufficient size to all entry of personnel. A classified area is any area 

classified Class I, Group D, Division 1 

or 2, following the guidelines of API RP 

500 (as incorporated by reference in 

§250.198), or any area classified Class I, 

Zone 0, Zone 1, or Zone 2, following the 

guidelines of API RP 505 (as incorporated by reference in §250.198). 

(ii) All detection systems shall be capable of continuous monitoring. Firedetection systems and portions of combustible gas-detection systems related 

to the higher gas concentration levels 

shall be of the manual-reset type. Combustible gas-detection systems related 

to the lower gas-concentration level 

may be of the automatic-reset type. 

(iii) A fuel-gas odorant or an automatic gas-detection and alarm system 

is required in enclosed, continuously 

manned areas of the facility which are 

provided with fuel gas. Living quarters 

and doghouses not containing a gas 

source and not located in a classified 

area do not require a gas detection system. 

(iv) The District Manager may require the installation and maintenance 

of a gas detector or alarm in any potentially hazardous area. 


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§ 250.804 30 CFR Ch. II (7–1–13 Edition) 

(v) Fire- and gas-detection systems 

must be an approved type, designed and 

installed according to API RP 14C, API 

RP 14G, and either API RP 14F or API 

RP 14FZ (the preceding four documents 

as incorporated by reference in 

§250.198). 

(10) Electrical equipment. Electrical 

equipment and systems shall be designed, installed, and maintained in accordance with the requirements in 

§250.114 of this part. 

(11) Erosion. A program of erosion 

control shall be in effect for wells or 

fields having a history of sand production. The erosion-control program may 

include sand probes, X-ray, ultrasonic, 

or other satisfactory monitoring methods. Records by lease, indicating the 

wells which have erosion-control programs in effect and the results of the 

programs, shall be maintained by the 

lessee for a period of 2 years and shall 

be made available to BSEE upon request. 

(c) General platform operations. (1) 

Surface or subsurface safety devices 

shall not be bypassed or blocked out of 

service unless they are temporarily out 

of service for startup, maintenance, or 

testing procedures. Only the minimum 

number of safety devices shall be taken 

out of service. Personnel shall monitor 

the bypassed or blocked-out functions 

until the safety devices are placed back 

in service. Any surface or subsurface 

safety device which is temporarily out 

of service shall be flagged. 

(2) When wells are disconnected from 

producing facilities and blind flanged, 

equipped with a tubing plug, or the 

master valves have been locked closed, 

you are not required to comply with 

the provisions of API RP 14C (as incorporated by reference in §250.198) or this 

regulation concerning the following: 

(i) Automatic fail-close SSV’s on 

wellhead assemblies, and 

(ii) The PSH and PSL shut-in sensors 

in flowlines from wells. 

(3) When pressure or atmospheric vessels are isolated from production facilities (e.g., inlet valve locked closed or 

inlet blind-flanged) and are to remain 

isolated for an extended period of time, 

safety device compliance with API RP 

14C or this subpart is not required. 

(4) All open-ended lines connected to 

producing facilities and wells shall be 

plugged or blind-flanged, except those 

lines designed to be open-ended such as 

flare or vent lines. 

(d) Welding and burning practices and 

procedures. All welding, burning, and 

hot-tapping activities shall be conducted according to the specific requirements in §§250.109 through 250.113 

of this part. 

§ 250.804 Production safety-system 

testing and records. 

(a) Inspection and testing. The safetysystem devices shall be successfully inspected and tested by the lessee at the 

interval specified below or more frequently if operating conditions warrant. Testing must be in accordance 

with API RP 14C, Appendix D (as incorporated by reference in §250.198), and 

the following: 

(1) Testing requirements for subsurface safety devices are as follows: 

(i) Each surface-controlled subsurface safety device installed in a 

well, including such devices in shut-in 

and injection wells, shall be tested in 

place for proper operation when installed or reinstalled and thereafter at 

intervals not exceeding 6 months. If 

the device does not operate properly, or 

if a liquid leakage rate in excess of 200 

cubic centimeters per minute or a gas 

leakage rate in excess of 5 cubic feet 

per minute is observed, the device shall 

be removed, repaired and reinstalled, 

or replaced. Testing shall be in accordance with API RP 14B (as incorporated 

by reference in §250.198) to ensure proper operation. 

(ii) Each subsurface-controlled SSSV 

installed in a well shall be removed, inspected, and repaired or adjusted, as 

necessary, and reinstalled or replaced 

at intervals not exceeding 6 months for 

those valves not installed in a landing 

nipple and 12 months for those valves 

installed in a landing nipple. 

(iii) Each tubing plug installed in a 

well shall be inspected for leakage by 

opening the well to possible flow at intervals not exceeding 6 months. If a liquid leakage rate in excess of 200 cubic 

centimeters per minute or a gas leakage rate in excess of 5 cubic feet per 

minute is observed, the device shall be 

removed, repaired and reinstalled, or 

replaced. An additional tubing plug 

may be installed in lieu of removal. 


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Safety & Environmental Enforcement, Interior § 250.804 

(iv) Injection valves shall be tested in 

the manner as outlined for testing tubing plugs in paragraph (a)(1)(iii) of this 

section. Leakage rates outlined in 

paragraph (a)(1)(iii) of this section 

shall apply. 

(2) All PSV’s shall be tested for operation at least once every 12 months. 

These valves shall be either bench-tested or equipped to permit testing with 

an external pressure source. Weighted 

disk vent valves used as PSV’s on atmospheric tanks may be disassembled 

and inspected in lieu of function testing. 

(3) The following safety devices (excluding electronic pressure transmitters and level sensors) must be tested 

at least once each calendar month, but 

at no time will more than 6 weeks 

elapse between tests: 

(i) All PSH and PSL, 

(ii) All LSH and LSL controls, 

(iii) All automatic inlet SDV’s which 

are actuated by a sensor on a vessel or 

compressor, and 

(iv) All SDV’s in liquid discharge 

lines and actuated by vessel low-level 

sensors. 

(4) The following electronic pressure 

transmitters and level sensors must be 

tested at least once every 3 months, 

but at no time may more than 120 days 

elapse between tests: 

(i) All PSH and PSL, and 

(ii) All LSH and LSL controls. 

(5) All SSV’s and USV’s shall be tested for operation and for leakage at 

least once each calendar month, but at 

no time shall more than 6 weeks elapse 

between tests. The SSV’s and USV’s 

must be tested in accordance with the 

test procedures specified in API RP 14H 

(as incorporated by reference in 

§250.198). If the SSV or USV does not 

operate properly or if any fluid flow is 

observed during the leakage test, the 

valve shall be repaired or replaced. 

(6) All flowline Flow Safety Valves 

(FSV) shall be checked for leakage at 

least once each calendar month, but at 

no time shall more than 6 weeks elapse 

between tests. The FSV’s must be tested for leakage in accordance with the 

test procedures specified in API RP 

14C, Appendix D, section D4, table D2, 

subsection D (as incorporated by reference in §250.198). If the leakage measured exceeds a liquid flow of 200 cubic 

centimeters per minute or a gas flow of 

5 cubic feet per minute, the FSV’s shall 

be repaired or replaced. 

(7) The TSH shutdown controls installed on compressor installations 

which can be nondestructively tested 

shall be tested every 6 months and repaired or replaced as necessary. 

(8) All pumps for firewater systems 

shall be inspected and operated weekly. 

(9) All fire- (flame, heat, or smoke) 

detection systems shall be tested for 

operation and recalibrated every 3 

months provided that testing can be 

performed in a nondestructive manner. 

Open flame or devices operating at 

temperatures which could ignite a 

methane-air mixture shall not be used. 

All combustible gas-detection systems 

shall be calibrated every 3 months. 

(10) All TSH devices shall be tested at 

least once every 12 months, excluding 

those addressed in paragraph (a)(7) of 

this section and those which would be 

destroyed by testing. Burner safety low 

and flow safety low devices shall also 

be tested at least once every 12 

months. 

(11) The ESD shall be tested for operation at least once each calendar 

month, but at no time shall more than 

6 weeks elapse between tests. The test 

shall be conducted by alternating ESD 

stations monthly to close at least one 

wellhead SSV and verify a surface-controlled SSSV closure for that well as 

indicated by control circuitry actuation. 

(12) Prior to the commencement of 

production, the lessee shall notify the 

District Manager when the lessee is 

ready to conduct a preproduction test 

and inspection of the integrated safety 

system. The lessee shall also notify the 

District Manager upon commencement 

of production in order that a complete 

inspection may be conducted. 

(b) Records. The lessee shall maintain 

records for a period of 2 years for each 

subsurface and surface safety device installed. These records shall be maintained by the lessee at the lessee’s field 

office nearest the OCS facility or other 

locations conveniently available to the 

District Manager. These records shall 

be available for review by a representative of BSEE. The records shall show 

the present status and history of each 

device, including dates and details of 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.805 30 CFR Ch. II (7–1–13 Edition) 

installation, removal, inspection, testing, repairing, adjustments, and reinstallation. 

§ 250.805 Safety device training. 

Personnel installing, inspecting, testing, and maintaining these safety devices and personnel operating the production platforms shall be qualified in 

accordance with 30 CFR 250, subpart O. 

§ 250.806 Safety and pollution prevention equipment quality assurance 

requirements. 

(a) General requirements. (1) Except as 

provided in paragraph (b)(1) of this section, you may install only certified 

safety and pollution prevention equipment (SPPE) in wells located on the 

OCS. SPPE includes the following: 

(i) Surface safety valves (SSV) and 

actuators; 

(ii) Underwater safety valves (USV) 

and actuators; and 

(iii) Subsurface safety valves (SSSV) 

and associated safety valve locks and 

landing nipples. 

(2) Certified SPPE is equipment the 

manufacturer certifies as manufactured under a quality assurance program BSEE recognizes. BSEE considers 

all other SPPE as noncertified. BSEE 

recognizes two quality assurance programs: 

(i) ANSI/ASME SPPE–1–1994 and 

SPPE–1d–1996 Addenda, Quality Assurance and Certification of Safety and 

Pollution Prevention Equipment Used 

in Offshore Oil and Gas Operations (as 

incorporated by reference in §250.198); 

and 

(ii) API Spec Q1, Specification for 

Quality Programs for the Petroleum, 

Petrochemical and Natural Gas Industry (as incorporated by reference in 

§250.198). 

(3) All SSV’s and USV’s must meet 

the technical specifications of API 

Spec 6A and 6AV1. All SSSVs must 

meet the technical specifications of 

API Specification 14A (as incorporated 

by reference in §250.198). However, 

SSSVs and related equipment planned 

to be used in high pressure high temperature environments must meet the 

additional requirements set forth in 

§250.807. 

(4) For information on all standards 

mentioned in this section, see §250.198. 

(b) Use of noncertified SPPE. (1) Before 

April 1, 1998, you may continue to use 

and install noncertified SPPE if it was 

in your inventory as of April 1, 1988, 

and was included in a list of noncertified SPPE submitted to BSEE prior 

to August 29, 1988. 

(2) On or after April 1, 1998: 

(i) You may not install additional 

noncertified SPPE; and 

(ii) When noncertified SPPE that is 

already in service requires offsite repair, remanufacturing, or hot work 

such as welding, you must replace it 

with certified SPPE. 

(c) Recognizing other quality assurance 

programs. The BSEE will consider recognizing other quality assurance programs covering the manufacture of 

SPPE. If you want BSEE to evaluate 

other quality assurance programs, submit relevant information about the 

program and reasons for recognition by 

BSEE to the Chief, Office of Offshore 

Regulatory Programs; Bureau of Safety and Environmental Enforcement; 

MS–4020; 381 Elden Street, Herndon, 

Virginia 20170–4817. 

§ 250.807 Additional requirements for 

subsurface safety valves and related equipment installed in high 

pressure high temperature (HPHT) 

environments. 

(a) If you plan to install SSSVs and 

related equipment in an HPHT environment, you must submit detailed information with your Application for Permit to Drill (APD), Application for 

Permit to Modify (APM), or Deepwater 

Operations Plan (DWOP) that demonstrates the SSSVs and related equipment are capable of performing in the 

applicable HPHT environment. Your 

detailed information must include the 

following: 

(1) A discussion of the SSSVs’ and related equipment’s design verification 

analysis; 

(2) A discussion of the SSSVs’ and related equipment’s design validation 

and functional testing process and procedures used; and 

(3) An explanation of why the analysis, process, and procedures ensure 

that the SSSVs and related equipment 

are fit-for-service in the applicable 

HPHT environment. 


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147 

Safety & Environmental Enforcement, Interior § 250.900 

(b) For this section, HPHT environment means when one or more of the 

following well conditions exist: 

(1) The completion of the well requires completion equipment or well 

control equipment assigned a pressure 

rating greater than 15,000 psig or a 

temperature rating greater than 350 degrees Fahrenheit; 

(2) The maximum anticipated surface 

pressure or shut-in tubing pressure is 

greater than 15,000 psig on the seafloor 

for a well with a subsea wellhead or at 

the surface for a well with a surface 

wellhead; or 

(3) The flowing temperature is equal 

to or greater than 350 degrees Fahrenheit on the seafloor for a well with a 

subsea wellhead or at the surface for a 

well with a surface wellhead. 

(c) For this section, related equipment includes wellheads, tubing heads, 

tubulars, packers, threaded connections, seals, seal assemblies, production trees, chokes, well control equipment, and any other equipment that 

will be exposed to the HPHT environment. 

§ 250.808 Hydrogen sulfide. 

Production operations in zones 

known to contain hydrogen sulfide 

(H2S) or in zones where the presence of 

H2S is unknown, as defined in §250.490 

of this part, shall be conducted in accordance with that section and other 

relevant requirements of subpart H, 

Production Safety Systems. 

Subpart I—Platforms and 

Structures 

GENERAL REQUIREMENTS FOR

PLATFORMS

§ 250.900 What general requirements 

apply to all platforms? 

(a) You must design, fabricate, install, use, maintain, inspect, and assess 

all platforms and related structures on 

the Outer Continental Shelf (OCS) so 

as to ensure their structural integrity 

for the safe conduct of drilling, 

workover, and production operations. 

In doing this, you must consider the 

specific environmental conditions at 

the platform location. 

(b) You must also submit an application under §250.905 of this subpart and 

obtain the approval of the Regional Supervisor before performing any of the 

activities described in the following 

table: 

Activity requiring application and approval Conditions for conducting the activity 

(1) Install a platform. This includes placing a newly constructed 

platform at a location or moving an existing platform to a 

new site.

(i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. 

(ii) If you are installing a floating platform, you must also adhere to U.S. Coast Guard (USCG) regulations for the fabrication, installation, and inspection of floating OCS facilities. 

(2) Major modification to any platform. This includes any structural changes that materially alter the approved plan or 

cause a major deviation from approved operations and any 

modification that increases loading on a platform by 10 percent or more.

(i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. 

(ii) Before you make a major modification to a floating platform, 

you must obtain approval from both the BSEE and the 

USCG for the modification. 

(3) Major repair of damage to any platform. This includes any 

corrective operations involving structural members affecting 

the structural integrity of a portion or all of the platform.

(i) You must adhere to the requirements of this subpart, including the industry standards in § 250.901. 

(ii) Before you make a major repair to a floating platform, you 

must obtain approval from both the BSEE and the USCG for 

the repair. 

(4) Convert an existing platform at the current location for a 

new purpose.

(i) The Regional Supervisor will determine on a case-by-case 

basis the requirements for an application for conversion of 

an existing platform at the current location. 

(ii) At a minimum, your application must include: the converted 

platform’s intended use; and a demonstration of the adequacy of the design and structural condition of the converted 

platform. 

(iii) If a floating platform, you must also adhere to USCG regulations for the fabrication, installation, and inspection of floating OCS facilities. 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.901 30 CFR Ch. II (7–1–13 Edition) 

Activity requiring application and approval Conditions for conducting the activity 

(5) Convert an existing mobile offshore drilling unit (MODU) for 

a new purpose.

(i) The Regional Supervisor will determine on a case-by-case 

basis the requirements for an application for conversion of 

an existing MODU. 

(ii) At a minimum, your application must include: the converted 

MODU’s intended location and use; a demonstration of the 

adequacy of the design and structural condition of the converted MODU; and a demonstration that the level of safety 

for the converted MODU is at least equal to that of re-used 

platforms. 

(iii) You must also adhere to USCG regulations for the fabrication, installation, and inspection of floating OCS facilities. 

(c) Under emergency conditions, you 

may make repairs to primary structural elements to restore an existing 

permitted condition without submitting an application or receiving prior 

BSEE approval for up to 120-calendar 

days following an event. You must notify the Regional Supervisor of the 

damage that occurred within 24 hours 

of its discovery, and you must provide 

a written completion report to the Regional Supervisor of the repairs that 

were made within 1 week after completing the repairs. If you make emergency repairs on a floating platform, 

you must also notify the USCG. 

(d) You must determine if your new 

platform or major modification to an 

existing platform is subject to the 

Platform Verification Program (PVP). 

Section 250.910 of this subpart fully describes the facilities that are subject to 

the PVP. If you determine that your 

platform is subject to the PVP, you 

must follow the requirements of 

§§250.909 through 250.918 of this subpart. 

(e) You must submit notification of 

the platform installation date and the 

final as-built location data to the Regional Supervisor within 45-calendar 

days of completion of platform installation. 

(1) For platforms not subject to the 

Platform Verification Program (PVP), 

BSEE will cancel the approved platform application 1 year after the approval has been granted if the platform 

has not been installed. If BSEE cancels 

the approval, you must resubmit your 

platform application and receive BSEE 

approval if you still plan to install the 

platform. 

(2) For platforms subject to the PVP, 

cancellation of an approval will be on 

an individual platform basis. For these 

platforms, BSEE will identify the date 

when the installation approval will be 

cancelled (if installation has not occurred) during the application and approval process. If BSEE cancels your 

installation approval, you must resubmit your platform application and receive BSEE approval if you still plan to 

install the platform. 

§ 250.901 What industry standards 

must your platform meet? 

(a) In addition to the other requirements of this subpart, your plans for 

platform design, analysis, fabrication, 

installation, use, maintenance, inspection and assessment must, as appropriate, conform to: 

(1) ACI Standard 318–95, Building 

Code Requirements for Reinforced Concrete (ACI 318–95) and Commentary 

(ACI 318R–95) (incorporated by reference at §250.198); 

(2) ACI 357R–84, Guide for the Design 

and Construction of Fixed Offshore 

Concrete Structures, 1984; reapproved 

1997 (incorporated by reference at 

§250.198); 

(3) ANSI/AISC 360–05, Specification 

for Structural Steel Buildings, (as 

specified in §250.198); 

(4) American Petroleum Institute 

(API) Bulletin 2INT–DG, Interim Guidance for Design of Offshore Structures 

for Hurricane Conditions, (as incorporated by reference in §250.198); 

(5) API Bulletin 2INT–EX, Interim 

Guidance for Assessment of Existing 

Offshore Structures for Hurricane Conditions, (as incorporated by reference 

in §250.198); 

(6) API Bulletin 2INT–MET, Interim 

Guidance on Hurricane Conditions in 

the Gulf of Mexico, (as incorporated by 

reference in §250.198); 


ehiers on DSK2VPTVN1PROD with CFR
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Safety & Environmental Enforcement, Interior § 250.901 

(7) API Recommend Practice (RP) 

2A–WSD, RP for Planning, Designing, 

and Constructing Fixed Offshore Platforms—Working Stress Design (as incorporated by reference in §250.198); 

(8) API RP 2FPS, Recommended 

Practice for Planning, Designing, and 

Constructing Floating Production Systems, (as incorporated by reference in 

§250.198); 

(9) API RP 2I, In-Service Inspection 

of Mooring Hardware for Floating 

Drilling Units (as incorporated by reference in §250.198); 

(10) API RP 2RD, Design of Risers for 

Floating Production Systems (FPSs) 

and Tension-Leg Platforms (TLPs), (as 

incorporated by reference in §250.198); 

(11) API RP 2SK, Recommended Practice for Design and Analysis of Station 

Keeping Systems for Floating Structures, (as incorporated by reference in 

§250.198); 

(12) API RP 2SM, Recommended 

Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, (as incorporated by reference in 

§250.198); 

(13) API RP 2T, Recommended Practice for Planning, Designing and Constructing Tension Leg Platforms, (as 

incorporated by reference in §250.198); 

(14) API RP 14J, Recommended Practice for Design and Hazards Analysis 

for Offshore Production Facilities, (as 

incorporated by reference in §250.198); 

(15) American Society for Testing 

and Materials (ASTM) Standard C 33– 

07, approved December 15, 2007, Standard Specification for Concrete Aggregates (as incorporated by reference in 

§250.198); 

(16) ASTM Standard C 94/C 94M–07, 

approved January 1, 2007, Standard 

Specification for Ready-Mixed Concrete (as incorporated by reference in 

§250.198); 

(17) ASTM Standard C 150–07, approved May 1, 2007, Standard Specification for Portland Cement (as incorporated by reference in §250.198); 

(18) ASTM Standard C 330–05, approved December 15, 2005, Standard 

Specification for Lightweight Aggregates for Structural Concrete (as incorporated by reference in §250.198); 

(19) ASTM Standard C 595–08, approved January 1, 2008, Standard Specification for Blended Hydraulic Cements 

(as incorporated by reference in 

§250.198); 

(20) AWS D1.1, Structural Welding 

Code—Steel, including Commentary, 

(as incorporated by reference in 

§250.198); 

(21) AWS D1.4, Structural Welding 

Code—Reinforcing Steel, (as incorporated by reference in §250.198); 

(22) AWS D3.6M, Specification for Underwater Welding, (as incorporated by 

reference in §250.198); 

(23) NACE Standard MR0175, Sulfide 

Stress Cracking Resistant Metallic Materials for Oilfield Equipment, (as incorporated by reference in §250.198); 

(24) NACE Standard RP0176–2003, 

Item No. 21018, Standard Recommended 

Practice, Corrosion Control of Steel 

Fixed Offshore Structures Associated 

with Petroleum Production. 

(b) You must follow the requirements 

contained in the documents listed 

under paragraph (a) of this section insofar as they do not conflict with other 

provisions of 30 CFR part 250. You may 

use applicable provisions of these documents, as approved by the Regional Supervisor, for the design, fabrication, 

and installation of platforms such as 

spars, since standards specifically written for such structures do not exist. 

You may also use alternative codes, 

rules, or standards, as approved by the 

Regional Supervisor, under the conditions enumerated in §250.141. 

(c) For information on the standards 

mentioned in this section, and where 

they may be obtained, see §250.198 of 

this part. 

(d) The following chart summarizes 

the applicability of the industry standards listed in this section for fixed and 

floating platforms: 

Industry standard Applicable to . . . 

(1) ACI Standard 318–95, Building Code Requirements for Reinforced Concrete (ACI 318–95) 

and Commentary (ACI 318R–95), 

Fixed and floating platform, as 

appropriate. 

(2) ANSI/AISC 360–05, Specification for Structural Steel Buildings; 

(3) API Bulletin 2INT–DG, Interim Guidance for Design of Offshore Structures for Hurricane 

Conditions; 


ehiers on DSK2VPTVN1PROD with CFR
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§ 250.902 30 CFR Ch. II (7–1–13 Edition) 

Industry standard Applicable to . . . 

(4) API Bulletin 2INT–EX, Interim Guidance for Assessment of Existing Offshore Structures for 

Hurricane Conditions; 

(5) API Bulletin 2INT–MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico; 

(6) API RP 2A–WSD, RP for Planning, Designing, and Constructing Fixed Offshore Platforms—Working Stress Design; 

(7) ASTM Standard C 33–07, approved December 15, 2007, Standard Specification for Concrete Aggregates; 

(8) ASTM Standard C 94/C 94M–07, approved January 1, 2007, Standard Specification for 

Ready-Mixed Concrete; 

(9) ASTM Standard C 150–07, approved May 1, 2007, Standard Specification for Portland Cement; 

(10) ASTM Standard C 330–05, approved December 15, 2005, Standard Specification for 

Lightweight Aggregates for Structural Concrete; 

(11) ASTM Standard C 595–08, approved January 1, 2008, Standard Specification for Blended 

Hydraulic Cements; 

(12) AWS D1.1, Structural Welding Code—Steel; 

(13) AWS D1.4, Structural Welding Code—Reinforcing Steel; 

(14) AWS D3.6M, Specification for Underwater Welding; 

(15) NACE Standard RP 0176–2003, Standard Recommended Practice (RP), Corrosion Control of Steel Fixed Offshore Platforms Associated with Petroleum Production; 

(16) ACI 357R–84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997, Fixed platforms. 

(17) API RP 14J, RP for Design and Hazards Analysis for Offshore Production Facilities; Floating platforms. 

(18) API RP 2FPS, RP for Planning, Designing, and Constructing, Floating Production Systems; 

(19) API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg 

Platforms (TLPs); 

(20) API RP 2SK, RP for Design and Analysis of Station Keeping Systems for Floating Structures; 

(21) API RP 2T, RP for Planning, Designing, and Constructing Tension Leg Platforms; 

(22) API RP 2SM, RP for Design, Manufacture, Installation, and Maintenance of Synthetic 

Fiber Ropes for Offshore Mooring; 

(23) API RP 2I, In-Service Inspection of Mooring Hardware for Floating Drilling Units 

§ 250.902 What are the requirements 

for platform removal and location 

clearance? 

You must remove all structures according to §§250.1725 through 250.1730 of 

Subpart Q—Decommissioning Activities of this part. 

§ 250.903 What records must I keep? 

(a) You must compile, retain, and 

make available to BSEE representatives for the functional life of all platforms: 

(1) The as-built drawings; 

(2) The design assumptions and analyses; 

(3) A summary of the fabrication and 

installation nondestructive examination records; 

(4) The inspection results from the 

inspections required by §250.919 of this 

subpart; and 

(5) Records of repairs not covered in 

the inspection report submitted under 

§250.919(b). 

(b) You must record and retain the 

original material test results of all primary structural materials during all 

stages of construction. Primary material is material that, should it fail, 

would lead to a significant reduction in 

platform safety, structural reliability, 

or operating capabilities. Items such as 

steel brackets, deck stiffeners and secondary braces or beams would not generally be considered primary structural 

members (or materials). 

(c) You must provide BSEE with the 

location of these records in the certification statement of your application 

for platform approval as required in 

§250.905(j). 

PLATFORM APPROVAL PROGRAM

§ 250.904 What is the Platform Approval Program? 

(a) The Platform Approval Program 

is the BSEE basic approval process for 

platforms on the OCS. The requirements of the Platform Approval Program are described in §§250.904 through 

250.908 of this subpart. Completing 

these requirements will satisfy BSEE 

criteria for approval of fixed platforms 

of a proven design that will be placed 

in the shallow water areas (≤ 400 ft.) of 

the Gulf of Mexico OCS. 


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Safety & Environmental Enforcement, Interior § 250.905 

(b) The requirements of the Platform 

Approval Program must be met by all 

platforms on the OCS. Additionally, if 

you want approval for a floating platform; a platform of unique design; or a 

platform being installed in deepwater 

(≤ 400 ft.) or a frontier area, you must 

also meet the requirements of the Platform Verification Program. The requirements of the Platform 

Verification Program are described in 

§§250.909 through 250.918 of this subpart. 

§ 250.905 How do I get approval for the 

installation, modification, or repair 

of my platform? 

The Platform Approval Program requires that you submit the information, documents, and fee listed in the 

following table for your proposed 

project. In lieu of submitting the paper 

copies specified in the table, you may 

submit your application electronically 

in accordance with 30 CFR 250.186(a)(3). 

Required submittal Required contents Other requirements 

(a) Application cover letter ........................ Proposed structure designation, lease 

number, area, name, and block number, and the type of facility your facility 

(e.g., drilling, production, quarters). 

The structure designation must be 

unique for the field (some fields are 

made up of several blocks); i.e. once 

a platform ‘‘A’’ has been used in the 

field there should never be another 

platform ‘‘A’’ even if the old platform 

‘‘A’’ has been removed. Single well 

free standing caissons should be 

given the same designation as the 

well. All other structures are to be 

designated by letter designations.

You must submit three copies. If, your 

facility is subject to the Platform 

Verification Program (PVP), you must 

submit four copies. 

(b) Location plat ........................................ Latitude and longitude coordinates, Universal Mercator grid-system coordinates, state plane coordinates in the 

Lambert or Transverse Mercator Projection System, and distances in feet 

from the nearest block lines. These 

coordinates must be based on the 

NAD (North American Datum) 27 

datum plane coordinate system.

Your plat must be drawn to a scale of 1 

inch equals 2,000 feet and include the 

coordinates of the lease block boundary lines. You must submit three copies. 

(c) Front, Side, and Plan View drawings .. Platform dimensions and orientation, elevations relative to M.L.L.W. (Mean 

Lower Low Water), and pile sizes and 

penetration.

Your drawing sizes must not exceed 

11′′×17′′. You must submit three copies (four copies for PVP applications). 

(d) Complete set of structural drawings .... The approved for construction fabrication 

drawings should be submitted including; e.g., cathodic protection systems; 

jacket design; pile foundations; drilling, 

production, and pipeline risers and 

riser tensioning systems; turrets and 

turret-and-hull interfaces; mooring and 

tethering systems; foundations and 

anchoring systems.

Your drawing sizes must not exceed 

11′′×17′′. You must submit one copy. 

(e) Summary of environmental data .......... A summary of the environmental data 

described in the applicable standards 

referenced under § 250.901(a) of this 

subpart and in § 250.198 of Subpart A, 

where the data is used in the design 

or analysis of the platform. Examples 

of relevant data include information on 

waves, wind, current, tides, temperature, snow and ice effects, marine 

growth, and water depth.

You must submit one copy. 


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§ 250.906 30 CFR Ch. II (7–1–13 Edition) 

Required submittal Required contents Other requirements 

(f) Summary of the engineering design 

data.

Loading information (e.g., live, dead, environmental), structural information 

(e.g., design-life; material types; cathodic protection systems; design criteria; fatigue life; jacket design; deck 

design; production component design; 

pile foundations; drilling, production, 

and pipeline risers and riser tensioning 

systems; turrets and turret-and-hull 

interfaces; foundations, foundation pilings and templates, and anchoring 

systems; mooring or tethering systems; fabrication and installation 

guidelines), and foundation information 

(e.g., soil stability, design criteria).

You must submit one copy. 

(g) Project-specific studies used in the 

platform design or installation.

All studies pertinent to platform design 

or installation, e.g., oceanographic 

and/or soil reports including the overall 

site investigative report required in 

§ 250.906.

You must submit one copy of each 

study. 

(h) Description of the loads imposed on 

the facility.

Loads imposed by jacket; decks; production components; drilling, production, 

and pipeline risers, and riser tensioning systems; turrets and turretand-hull interfaces; foundations, foundation pilings and templates, and anchoring systems; and mooring or tethering systems.

You must submit one copy. 

(i) Summary of safety factors utilized ........ A summary of pertinent derived factors 

of safety against failure for major 

structural members, e.g., unity check 

ratios exceeding 0.85 for steel-jacket 

platform members, indicated on ‘‘line’’ 

sketches of jacket sections.

You must submit one copy. 

(j) A copy of the in-service inspection plan This plan is described in § 250.919 ........ You must submit one copy. 

(k) Certification statement ......................... The following statement: ‘‘The design of 

this structure has been certified by a 

recognized classification society, or a 

registered civil or structural engineer 

or equivalent, or a naval architect or 

marine engineer or equivalent, specializing in the design of offshore 

structures. The certified design and 

as-built plans and specifications will 

be on file at (give location)’’.

An authorized company representative 

must sign the statement. You must 

submit one copy. 

(l) Payment of the service fee listed in 

§ 250.125. 

§ 250.906 What must I do to obtain approval for the proposed site of my 

platform? 

(a) Shallow hazards surveys. You must 

perform a high-resolution or acousticprofiling survey to obtain information 

on the conditions existing at and near 

the surface of the seafloor. You must 

collect information through this survey sufficient to determine the presence of the following features and their 

likely effects on your proposed platform: 

(1) Shallow faults; 

(2) Gas seeps or shallow gas; 

(3) Slump blocks or slump sediments; 

(4) Shallow water flows; 

(5) Hydrates; or 

(6) Ice scour of seafloor sediments. 

(b) Geologic surveys. You must perform a geological survey relevant to 

the design and siting of your platform. 

Your geological survey must assess: 

(1) Seismic activity at your proposed 

site; 

(2) Fault zones, the extent and geometry of faulting, and attenuation effects of geologic conditions near your 

site; and 

(3) For platforms located in producing areas, the possibility and effects 

of seafloor subsidence. 

(c) Subsurface surveys. Depending 

upon the design and location of your 

proposed platform and the results of 


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Safety & Environmental Enforcement, Interior § 250.908 

the shallow hazard and geologic surveys, the Regional Supervisor may require you to perform a subsurface survey. This survey will include a testing 

program for investigating the stratigraphic and engineering properties of 

the soil that may affect the foundations or anchoring systems for your facility. The testing program must include adequate in situ testing, boring, 

and sampling to examine all important 

soil and rock strata to determine its 

strength classification, deformation 

properties, and dynamic characteristics. If required to perform a subsurface survey, you must prepare and 

submit to the Regional Supervisor a 

summary report to briefly describe the 

results of your soil testing program, 

the various field and laboratory test 

methods employed, and the applicability of these methods as they pertain 

to the quality of the samples, the type 

of soil, and the anticipated design application. You must explain how the 

engineering properties of each soil 

stratum affect the design of your platform. In your explanation you must describe the uncertainties inherent in 

your overall testing program, and the 

reliability and applicability of each 

test method. 

(d) Overall site investigation report. 

You must prepare and submit to the 

Regional Supervisor an overall site investigation report for your platform 

that integrates the findings of your 

shallow hazards surveys and geologic 

surveys, and, if required, your subsurface surveys. Your overall site investigation report must include analyses of the potential for: 

(1) Scouring of the seafloor; 

(2) Hydraulic instability; 

(3) The occurrence of sand waves; 

(4) Instability of slopes at the platform location; 

(5) Liquefaction, or possible reduction of soil strength due to increased 

pore pressures; 

(6) Degradation of subsea permafrost 

layers; 

(7) Cyclic loading; 

(8) Lateral loading; 

(9) Dynamic loading; 

(10) Settlements and displacements; 

(11) Plastic deformation and formation collapse mechanisms; and 

(12) Soil reactions on the platform 

foundations or anchoring systems. 

§ 250.907 Where must I locate foundation boreholes? 

(a) For fixed or bottom-founded platforms and tension leg platforms, your 

maximum distance from any foundation pile to a soil boring must not exceed 500 feet. 

(b) For deepwater floating platforms 

which utilize catenary or taut-leg 

moorings, you must take borings at 

the most heavily loaded anchor location, at the anchor points approximately 120 and 240 degrees around the 

anchor pattern from that boring, and, 

as necessary, other points throughout 

the anchor pattern to establish the soil 

profile suitable for foundation design 

purposes. 

§ 250.908 What are the minimum structural fatigue design requirements? 

(a) API RP 2A–WSD, Recommended 

Practice for Planning, Designing and 

Constructing Fixed Offshore Platforms 

(as incorporated by reference in 

§250.198), requires that the design fatigue life of each joint and member be 

twice the intended service life of the 

structure. When designing your platform, the following table provides minimum fatigue life safety factors for 

critical structural members and joints. 

If . . . Then . . . 

(1) There is sufficient structural redundancy to prevent catastrophic failure of the platform or structure under consideration, 

The results of the analysis must indicate a maximum calculated life of twice the design life of the platform. 

(2) There is not sufficient structural redundancy to prevent catastrophic failure of the platform or structure, The results of a fatigue analysis must indicate a minimum calculated life or three times the design life of the platform. 

(3) The desirable degree of redundancy is significantly reduced 

as a result of fatigue damage, 

The results of a fatigue analysis must indicate a minimum calculated life of three times the design life of the platform. 

(b) The documents incorporated by 

reference in §250.901 may require larger 

safety factors than indicated in paragraph (a) of this section for some key 


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§ 250.909 30 CFR Ch. II (7–1–13 Edition) 

components. When the documents incorporated by reference require a larger safety factor than the chart in paragraph (a) of this section, the requirements of the incorporated document 

will prevail. 

PLATFORM VERIFICATION PROGRAM

§ 250.909 What is the Platform 

Verification Program? 

The Platform Verification Program 

is the BSEE approval process for ensuring that floating platforms; platforms 

of a new or unique design; platforms in 

seismic areas; or platforms located in 

deepwater or frontier areas meet stringent requirements for design and construction. The program is applied during construction of new platforms and 

major modifications of, or repairs to, 

existing platforms. These requirements 

are in addition to the requirements of 

the Platform Approval Program described in §§250.904 through 250.908 of 

this subpart. 

§ 250.910 Which of my facilities are 

subject to the Platform Verification 

Program? 

(a) All new fixed or bottom-founded 

platforms that meet any of the following five conditions are subject to 

the Platform Verification Program: 

(1) Platforms installed in water 

depths exceeding 400 feet (122 meters); 

(2) Platforms having natural periods 

in excess of 3 seconds; 

(3) Platforms installed in areas of unstable bottom conditions; 

(4) Platforms having configurations 

and designs which have not previously 

been used or proven for use in the area; 

or 

(5) Platforms installed in seismically 

active areas. 

(b) All new floating platforms are 

subject to the Platform Verification 

Program to the extent indicated in the 

following table: 

If . . . Then . . . 

(1) Your new floating platform is a buoyant offshore facility that 

does not have a ship-shaped hull, 

The entire platform is subject to the Platform Verification Program including the following associated structures: 

(i) Drilling, production, and pipeline risers, and riser tensioning 

systems (each platform must be designed to accommodate 

all the loads imposed by all risers and riser does not have 

tensioning systems); 

(ii) Turrets and turret-and-hull interfaces; 

(iii) Foundations, foundation pilings and templates, and anchoring systems; and 

(iv) Mooring or tethering systems. 

(2) Your new floating platform is a buoyant offshore facility with 

a ship-shaped hull, 

Only the following structures that may be associated with a 

floating platform are subject to the Platform Verification Program: 

(i) Drilling, production, and pipeline risers, and riser tensioning 

systems (each platform must be designed to accommodate 

all the loads imposed by all risers and riser tensioning systems); 

(ii) Turrets and turret-and-hull interfaces; 

(iii) Foundations, foundation pilings and templates, and anchoring systems; and 

(iv) Mooring or tethering systems. 

(c) If a platform is originally subject 

to the Platform Verification Program, 

then the conversion of that platform at 

that same site for a new purpose, or 

making a major modification of, or 

major repair to, that platform, is also 

subject to the Platform Verification 

Program. A major modification includes any modification that increases 

loading on a platform by 10 percent or 

more. A major repair is a corrective operation involving structural members 

affecting the structural integrity of a 

portion or all of the platform. Before 

you make a major modification or repair to a floating platform, you must 

obtain approval from both the BSEE 

and the USCG. 

(d) The applicability of Platform 

Verification Program requirements to 

other types of facilities will be determined by BSEE on a case-by-case basis. 


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Safety & Environmental Enforcement, Interior § 250.912 

§ 250.911 If my platform is subject to 

the Platform Verification Program, 

what must I do? 

If your platform, conversion, or 

major modification or repair meets the 

criteria in §250.910, you must: 

(a) Design, fabricate, install, use, 

maintain and inspect your platform, 

conversion, or major modification or 

repair to your platform according to 

the requirements of this subpart, and 

the applicable documents listed in 

§250.901(a) of this subpart; 

(b) Comply with all the requirements 

of the Platform Approval Program 

found in §§250.904 through 250.908 of 

this subpart. 

(c) Submit for the Regional Supervisor’s approval three copies each of 

the design verification, fabrication 

verification, and installation 

verification plans required by §250.912; 

(d) Submit a complete schedule of all 

phases of design, fabrication, and installation for the Regional Supervisor’s 

approval. You must include a project 

management timeline, Gantt Chart, 

that depicts when interim and final reports required by §§250.916, 250.917, and 

250.918 will be submitted to the Regional Supervisor for each phase. On 

the timeline, you must break-out the 

specific scopes of work that inherently 

stand alone (e.g., deck, mooring systems, tendon systems, riser systems, 

turret systems). 

(e) Include your nomination of a Certified Verification Agent (CVA) as a 

part of each verification plan required 

by §250.912; 

(f) Follow the additional requirements in §§250.913 through 250.918; 

(g) Obtain approval for modifications 

to approved plans and for major deviations from approved installation procedures from the Regional Supervisor; 

and 

(h) Comply with applicable USCG 

regulations for floating OCS facilities. 

§ 250.912 What plans must I submit 

under the Platform Verification 

Program? 

If your platform, associated structure, or major modification meets the 

criteria in §250.910, you must submit 

the following plans to the Regional Supervisor for approval: 

(a) Design verification plan. You may 

submit your design verification plan to 

BSEE with or subsequent to the submittal of your Development and Production Plan (DPP) or Development 

Operations Coordination Document 

(DOCD) to BOEM. Your design 

verification must be conducted by, or 

be under the direct supervision of, a 

registered professional civil or structural engineer or equivalent, or a naval 

architect or marine engineer or equivalent, with previous experience in directing the design of similar facilities, 

systems, structures, or equipment. For 

floating platforms, you must ensure 

that the requirements of the USCG for 

structural integrity and stability, e.g., 

verification of center of gravity, etc., 

have been met. Your design 

verification plan must include the following: 

(1) All design documentation specified in §250.905 of this subpart; 

(2) Abstracts of the computer programs used in the design process; and 

(3) A summary of the major design 

considerations and the approach to be 

used to verify the validity of these design considerations. 

(b) Fabrication verification plan. The 

Regional Supervisor must approve your 

fabrication verification plan before you 

may initiate any related operations. 

Your fabrication verification plan must 

include the following: 

(1) Fabrication drawings and material specifications for artificial island 

structures and major members of concrete-gravity and steel-gravity structures; 

(2) For jacket and floating structures, all the primary load-bearing 

members included in the space-frame 

analysis; and 

(3) A summary description of the following: 

(i) Structural tolerances; 

(ii) Welding procedures; 

(iii) Material (concrete, gravel, or 

silt) placement methods; 

(iv) Fabrication standards; 

(v) Material quality-control procedures; 

(vi) Methods and extent of nondestructive examinations for welds and 

materials; and 

(vii) Quality assurance procedures. 


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§ 250.913 30 CFR Ch. II (7–1–13 Edition) 

(c) Installation verification plan. The 

Regional Supervisor must approve your 

installation verification plan before 

you may initiate any related operations. Your installation verification 

plan must include: 

(1) A summary description of the 

planned marine operations; 

(2) Contingencies considered; 

(3) Alternative courses of action; and 

(4) An identification of the areas to 

be inspected. You must specify the acceptance and rejection criteria to be 

used for any inspections conducted during installation, and for the post-installation verification inspection. 

(d) You must combine fabrication 

verification and installation 

verification plans for manmade islands 

or platforms fabricated and installed in 

place. 

§ 250.913 When must I resubmit Platform Verification Program plans? 

(a) You must resubmit any design 

verification, fabrication verification, 

or installation verification plan to the 

Regional Supervisor for approval if: 

(1) The CVA changes; 

(2) The CVA’s or assigned personnel’s 

qualifications change; or 

(3) The level of work to be performed 

changes. 

(b) If only part of a verification plan 

is affected by one of the changes described in paragraph (a) of this section, 

you can resubmit only the affected 

part. You do not have to resubmit the 

summary of technical details unless 

you make changes in the technical details. 

§ 250.914 How do I nominate a CVA? 

(a) As part of your design 

verification, fabrication verification, 

or installation verification plan, you 

must nominate a CVA for the Regional 

Supervisor’s approval. You must specify whether the nomination is for the 

design, fabrication, or installation 

phase of verification, or for any combination of these phases. 

(b) For each CVA, you must submit a 

list of documents to be forwarded to 

the CVA, and a qualification statement 

that includes the following: 

(1) Previous experience in third-party 

verification or experience in the design, fabrication, installation, or major 

modification of offshore oil and gas 

platforms. This should include fixed 

platforms, floating platforms, manmade islands, other similar marine 

structures, and related systems and 

equipment; 

(2) Technical capabilities of the individual or the primary staff for the specific project; 

(3) Size and type of organization or 

corporation; 

(4) In-house availability of, or access 

to, appropriate technology. This should 

include computer programs, hardware, 

and testing materials and equipment; 

(5) Ability to perform the CVA functions for the specific project considering current commitments; 

(6) Previous experience with BSEE 

requirements and procedures; 

(7) The level of work to be performed 

by the CVA. 

§ 250.915 What are the CVA’s primary 

responsibilities? 

(a) The CVA must conduct specified 

reviews according to §§250.916, 250.917, 

and 250.918 of this subpart. 

(b) Individuals or organizations acting as CVAs must not function in any 

capacity that would create a conflict of 

interest, or the appearance of a conflict 

of interest. 

(c) The CVA must consider the applicable provisions of the documents listed in §250.901(a); the alternative codes, 

rules, and standards approved under 

§250.901(b); and the requirements of 

this subpart. 

(d) The CVA is the primary contact 

with the Regional Supervisor and is directly responsible for providing immediate reports of all incidents that affect the design, fabrication and installation of the platform. 

§ 250.916 What are the CVA’s primary 

duties during the design phase? 

(a) The CVA must use good engineering judgment and practices in conducting an independent assessment of 

the design of the platform, major modification, or repair. The CVA must ensure that the platform, major modification, or repair is designed to withstand the environmental and functional load conditions appropriate for 

the intended service life at the proposed location. 


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Safety & Environmental Enforcement, Interior § 250.917 

(b) Primary duties of the CVA during 

the design phase include the following: 

Type of facility . . . The CVA must . . . 

(1) For fixed platforms and non-shipshaped floating facilities, Conduct an independent assessment of all proposed: 

(i) Planning criteria; 

(ii) Operational requirements; 

(iii) Environmental loading data; 

(iv) Load determinations; 

(v) Stress analyses; 

(vi) Material designations; 

(vii) Soil and foundation conditions; 

(viii) Safety factors; and 

(ix) Other pertinent parameters of the proposed design. 

(2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard for structural integrity and 

stability, e.g., verification of center of gravity, etc., have been met. The CVA 

must also consider: 

(i) Drilling, production, and pipeline risers, and riser tensioning systems; 

(ii) Turrets and turret-and-hull interfaces; 

(iii) Foundations, foundation pilings and templates, and anchoring systems; and 

(iv) Mooring or tethering systems. 

(c) The CVA must submit interim reports and a final report to the Regional 

Supervisor, and to you, during the design phase in accordance with the approved schedule required by §250.911(d). 

In each interim and final report the 

CVA must: 

(1) Provide a summary of the material reviewed and the CVA’s findings; 

(2) In the final CVA report, make a 

recommendation that the Regional Supervisor either accept, request modifications, or reject the proposed design 

unless such a recommendation has 

been previously made in an interim report; 

(3) Describe the particulars of how, 

by whom, and when the independent review was conducted; and 

(4) Provide any additional comments 

the CVA deems necessary. 

§ 250.917 What are the CVA’s primary 

duties during the fabrication 

phase? 

(a) The CVA must use good engineering judgment and practices in conducting an independent assessment of 

the fabrication activities. The CVA 

must monitor the fabrication of the 

platform or major modification to ensure that it has been built according to 

the approved design and the fabrication 

plan. If the CVA finds that fabrication 

procedures are changed or design specifications are modified, the CVA must 

inform you. If you accept the modifications, then the CVA must so inform the 

Regional Supervisor. 

(b) Primary duties of the CVA during 

the fabrication phase include the following: 

Type of facility . . . The CVA must . . . 

(1) For all fixed platforms and non-shipshaped floating facilities, Make periodic onsite inspections while fabrication is in progress and must verify 

the following fabrication items, as appropriate: 

(i) Quality control by lessee and builder; 

(ii) Fabrication site facilities; 

(iii) Material quality and identification methods; 

(iv) Fabrication procedures specified in the approved plan, and adherence to such 

procedures; 

(v) Welder and welding procedure qualification and identification; 

(vi) Structural tolerances specified and adherence to those tolerances; 

(vii) The nondestructive examination requirements, and evaluation results of the 

specified examinations; 

(viii) Destructive testing requirements and results; 

(ix) Repair procedures; 

(x) Installation of corrosion-protection systems and splash-zone protection; 

(xi) Erection procedures to ensure that overstressing of structural members does 

not occur; 

(xii) Alignment procedures; 

(xiii) Dimensional check of the overall structure, including any turrets, turret-andhull interfaces, any mooring line and chain and riser tensioning line segments; 

and 


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§ 250.918 30 CFR Ch. II (7–1–13 Edition) 

Type of facility . . . The CVA must . . . 

(xiv) Status of quality-control records at various stages of fabrication. 

(2) For all floating facilities, Ensure that the requirements of the U.S. Coast Guard floating for structural integrity and stability, e.g., verification of center of gravity, etc., have been met. The 

CVA must also consider: 

(i) Drilling, production, and pipeline risers, and riser tensioning systems (at least for 

the initial fabrication of these elements); 

(ii) Turrets and turret-and-hull interfaces; 

(iii) Foundation pilings and templates, and anchoring systems; and 

(iv) Mooring or tethering systems. 

(c) The CVA must submit interim reports and a final report to the Regional 

Supervisor, and to you, during the fabrication phase in accordance with the 

approved schedule required by 

§250.911(d). In each interim and final 

report the CVA must: 

(1) Give details of how, by whom, and 

when the independent monitoring activities were conducted; 

(2) Describe the CVA’s activities during the verification process; 

(3) Summarize the CVA’s findings; 

(4) Confirm or deny compliance with 

the design specifications and the approved fabrication plan; 

(5) In the final CVA report, make a 

recommendation to accept or reject 

the fabrication unless such a recommendation has been previously 

made in an interim report; and 

(6) Provide any additional comments 

that the CVA deems necessary. 

§ 250.918 What are the CVA’s primary 

duties during the installation 

phase? 

(a) The CVA must use good engineering judgment and practice in conducting an independent assessment of 

the installation activities. 

(b) Primary duties of the CVA during 

the installation phase include the following: 

The CVA must . . . Operation or equipment to be inspected . . . 

(1) Verify, as appropriate, (i) Loadout and initial flotation operations; 

(ii) Towing operations to the specified location, and review the towing records; 

(iii) Launching and uprighting operations; 

(iv) Submergence operations; 

(v) Pile or anchor installations; 

(vi) Installation of mooring and tethering systems; 

(vii) Final deck and component installations; and 

(viii) Installation at the approved location according to the approved design and the 

installation plan. 

(2) Witness (for a fixed or floating platform), (i) The loadout of the jacket, decks, piles, or structures from each fabrication site; 

(ii) The actual installation of the platform or major modification and the related installation activities. 

(3) Witness (for a floating platform), (i) The loadout of the platform; 

(ii) The installation of drilling, production, and pipeline risers, and riser tensioning 

systems (at least for the initial installation of these elements); 

(iii) The installation of turrets and turret-and-hull interfaces; 

(iv) The installation of foundation pilings and templates, and anchoring systems; 

and 

(v) The installation of the mooring and tethering systems. 

(4) Conduct an onsite survey, Survey the platform after transportation to the approved location. 

(5) Spot-check as necessary to determine 

compliance with the applicable documents listed in § 250.901(a); the alternative codes, rules and standards approved under § 250.901(b); the requirements listed in § 250.903 and §§ 250.906 

through 250.908 of this subpart and the 

approved plans, 

(i) Equipment; 

(ii) Procedures; and 

(iii) Recordkeeping. 

(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the installation phase in accordance with the 


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Safety & Environmental Enforcement, Interior § 250.920 

approved schedule required by 

§250.911(d). In each interim and final 

report the CVA must: 

(1) Give details of how, by whom, and 

when the independent monitoring activities were conducted; 

(2) Describe the CVA’s activities during the verification process; 

(3) Summarize the CVA’s findings; 

(4) Confirm or deny compliance with 

the approved installation plan; 

(5) In the final report, make a recommendation to accept or reject the 

installation unless such a recommendation has been previously made in an interim report; and 

(6) Provide any additional comments 

that the CVA deems necessary. 

INSPECTION, MAINTENANCE, AND

ASSESSMENT OF PLATFORMS

§ 250.919 What in-service inspection 

requirements must I meet? 

(a) You must submit a comprehensive 

in-service inspection report annually 

by November 1 to the Regional Supervisor that must include: 

(1) A list of fixed and floating platforms you inspected in the preceding 12 

months; 

(2) The extent and area of inspection 

for both the above-water and underwater portions of the platform and the 

pertinent components of the mooring 

system for floating platforms; 

(3) The type of inspection employed 

(e.g., visual, magnetic particle, ultrasonic testing); 

(4) The overall structural condition 

of each platform, including a corrosion 

protection evaluation; and 

(5) A summary of the inspection results indicating what repairs, if any, 

were needed. 

(b) If any of your structures have 

been exposed to a natural occurrence 

(e.g., hurricane, earthquake, or tropical storm), the Regional Supervisor 

may require you to submit an initial 

report of all structural damage, followed by subsequent updates, which include the following: 

(1) A list of affected structures; 

(2) A timetable for conducting the inspections described in section 14.4.3 of 

API RP 2A–WSD (as incorporated by 

reference in §250.198); and 

(3) An inspection plan for each structure that describes the work you will 

perform to determine the condition of 

the structure. 

(c) The Regional Supervisor may also 

require you to submit the results of the 

inspections referred to in paragraph 

(b)(2) of this section, including a description of any detected damage that 

may adversely affect structural integrity, an assessment of the structure’s 

ability to withstand any anticipated 

environmental conditions, and any remediation plans. Under §§250.900(b)(3) 

and 250.905, you must obtain approval 

from BSEE before you make major repairs of any damage unless you meet 

the requirements of §250.900(c). 

§ 250.920 What are the BSEE requirements for assessment of fixed platforms? 

(a) You must document all wells, 

equipment, and pipelines supported by 

the platform if you intend to use either 

the A–2 or A–3 assessment category. 

Assessment categories are defined in 

API RP 2A–WSD, Section 17.3 (as incorporated by reference in §250.198). If 

BSEE objects to the assessment category you used for your assessment, 

you may need to redesign and/or modify the platform to adequately demonstrate that the platform is able to 

withstand the environmental loadings 

for the appropriate assessment category. 

(b) You must perform an analysis 

check when your platform will have additional personnel, additional topside 

facilities, increased environmental or 

operational loading, or inadequate 

deck height your platform suffered significant damage (e.g., experienced damage to primary structural members or 

conductor guide trays or global structural integrity is adversely affected); 

or the exposure category changes to a 

more restrictive level (see Sections 

17.2.1 through 17.2.5 of API RP 2A–WSD, 

incorporated by reference in §250.198, 

for a description of assessment 

initiators). 

(c) You must initiate mitigation actions for platforms that do not pass the 

assessment process of API RP 2A–WSD. 

You must submit applications for your 

mitigation actions (e.g., repair, modification, decommissioning) to the Regional Supervisor for approval before 

you conduct the work. 


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§ 250.921 30 CFR Ch. II (7–1–13 Edition) 

(d) The BSEE may require you to 

conduct a platform design basis check 

when the reduced environmental loading criteria contained in API RP 2A– 

WSD Section 17.6 are not applicable. 

(e) By November 1, 2009, you must 

submit a complete list of all the platforms you operate, together with all 

the appropriate data to support the assessment category you assign to each 

platform and the platform assessment 

initiators (as defined in API RP 2A– 

WSD) to the Regional Supervisor. You 

must submit subsequent complete lists 

and the appropriate data to support the 

consequence-of-failure category every 5 

years thereafter, or as directed by the 

Regional Supervisor. 

(f) The use of Section 17, Assessment 

of Existing Platforms, of API RP 2A– 

WSD is limited to existing fixed structures that are serving their original approved purpose. You must obtain approval from the Regional Supervisor 

for any change in purpose of the platform, following the provisions of API 

RP 2A–WSD, Section 15, Re-use. 

§ 250.921 How do I analyze my platform for cumulative fatigue? 

(a) If you are required to analyze cumulative fatigue on your platform because of the results of an inspection or 

platform assessment, you must ensure 

that the safety factors for critical elements listed in §250.908 are met or exceeded. 

(b) If the calculated life of a joint or 

member does not meet the criteria of 

§250.908, you must either mitigate the 

load, strengthen the joint or member, 

or develop an increased inspection 

process. 

Subpart J—Pipelines and Pipeline 

Rights-of-Way 

§ 250.1000 General requirements. 

(a) Pipelines and associated valves, 

flanges, and fittings shall be designed, 

installed, operated, maintained, and 

abandoned to provide safe and pollution-free transportation of fluids in a 

manner which does not unduly interfere with other uses in the Outer Continental Shelf (OCS). 

(b) An application must be accompanied by payment of the service fee 

listed in §250.125 and submitted to the 

Regional Supervisor and approval obtained before: 

(1) Installation, modification, or 

abandonment of a lease term pipeline; 

(2) Installation or modification of a 

right-of-way (other than lease term) 

pipeline; or 

(3) Modification or relinquishment of 

a pipeline right-of way. 

(c)(1) Department of the Interior 

(DOI) pipelines, as defined in §250.1001, 

must meet the requirements in 

§§250.1000 through 250.1008. 

(2) A pipeline right-of-way grant 

holder must identify in writing to the 

Regional Supervisor the operator of 

any pipeline located on its right-ofway, if the operator is different from 

the right-of-way grant holder. 

(3) A producing operator must identify for its own records, on all existing 

pipelines located on its lease or rightof-way, the specific points at which operating responsibility transfers to a 

transporting operator. 

(i) Each producing operator must, if 

practical, durably mark all of its 

above-water transfer points by April 14, 

1999, or the date a pipeline begins service, whichever is later. 

(ii) If it is not practical to durably 

mark a transfer point, and the transfer 

point is located above water, then the 

operator must identify the transfer 

point on a schematic located on the facility. 

(iii) If a transfer point is located 

below water, then the operator must 

identify the transfer point on a schematic and provide the schematic to 

BSEE upon request. 

(iv) If adjoining producing and transporting operators cannot agree on a 

transfer point by April 14, 1999, the 

BSEE Regional Supervisor and the Department of Transportation (DOT) Office of Pipeline Safety (OPS) Regional 

Director may jointly determine the 

transfer point. 

(4) The transfer point serves as a regulatory boundary. An operator may 

write to the BSEE Regional Supervisor 

to request an exception to this requirement for an individual facility or area. 

The Regional Supervisor, in consultation with the OPS Regional Director 

and affected parties, may grant the request. 


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Safety & Environmental Enforcement, Interior § 250.1000 

(5) Pipeline segments designed, constructed, maintained, and operated 

under DOT regulations but transferring 

to DOI regulation as of October 16, 1998, 

may continue to operate under DOT design and construction requirements 

until significant modifications or repairs are made to those segments. 

After October 16, 1998, BSEE operational and maintenance requirements 

will apply to those segments. 

(6) Any producer operating a pipeline 

that crosses into State waters without 

first connecting to a transporting operator’s facility on the OCS must comply 

with this subpart. Compliance must extend from the point where hydrocarbons are first produced, through and 

including the last valve and associated 

safety equipment (e.g., pressure safety 

sensors) on the last production facility 

on the OCS. 

(7) Any producer operating a pipeline 

that connects facilities on the OCS 

must comply with this subpart. 

(8) Any operator of a pipeline that 

has a valve on the OCS downstream 

(landward) of the last production facility may ask in writing that the BSEE 

Regional Supervisor recognize that 

valve as the last point BSEE will exercise its regulatory authority. 

(9) A pipeline segment is not subject 

to BSEE regulations for design, construction, operation, and maintenance 

if: 

(i) It is downstream (generally shoreward) of the last valve and associated 

safety equipment on the last production facility on the OCS; and 

(ii) It is subject to regulation under 

49 CFR parts 192 and 195. 

(10) DOT may inspect all upstream 

safety equipment (including valves, 

over-pressure protection devices, cathodic protection equipment, and pigging devices, etc.) that serve to protect 

the integrity of DOT-regulated pipeline 

segments. 

(11) OCS pipeline segments not subject to DOT regulation under 49 CFR 

parts 192 and 195 are subject to all 

BSEE regulations. 

(12) A producer may request that its 

pipeline operate under DOT regulations 

governing pipeline design, construction, operation, and maintenance. 

(i) The operator’s request must be in 

the form of a written petition to the 

BSEE Regional Supervisor that states 

the justification for the pipeline to operate under DOT regulation. 

(ii) The Regional Supervisor will decide, on a case-by-case basis, whether 

to grant the operator’s request. In considering each petition, the Regional 

Supervisor will consult with the Office 

of Pipeline Safety (OPS) Regional Director. 

(13) A transporter who operates a 

pipeline regulated by DOT may request 

to operate under BSEE regulations 

governing pipeline operation and maintenance. Any subsequent repairs or 

modifications will also be subject to 

BSEE regulations governing design and 

construction. 

(i) The operator’s request must be in 

the form of a written petition to the 

OPS Regional Director and the BSEE 

Regional Supervisor. 

(ii) The BSEE Regional Supervisor 

and the OPS Regional Director will decide how to act on this petition. 

(d) A pipeline which qualifies as a 

right-of-way pipeline (see §250.1001, 

Definitions) shall not be installed until 

a right-of-way has been requested and 

granted in accordance with this subpart. 

(e)(1) The Regional Supervisor may 

suspend any pipeline operation upon a 

determination by the Regional Supervisor that continued activity would 

threaten or result in serious, irreparable, or immediate harm or damage 

to life (including fish and other aquatic 

life), property, mineral deposits, or the 

marine, coastal, or human environment. 

(2) The Regional Supervisor may also 

suspend pipeline operations or a rightof-way grant if the Regional Supervisor 

determines that the lessee or right-ofway holder has failed to comply with a 

provision of the Act or any other applicable law, a provision of these or other 

applicable regulations, or a condition 

of a permit or right-of-way grant. 

(3) The Secretary of the Interior 

(Secretary) may cancel a pipeline permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A rightof-way grant may be forfeited in accordance with 43 U.S.C. 1334(e). 


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§ 250.1001 30 CFR Ch. II (7–1–13 Edition) 

§ 250.1001 Definitions. 

Terms used in this subpart shall have 

the meanings given below: 

DOI pipelines include: 

(1) Producer-operated pipelines extending upstream (generally seaward) 

from each point on the OCS at which 

operating responsibility transfers from 

a producing operator to a transporting 

operator; 

(2) Producer-operated pipelines extending upstream (generally seaward) 

of the last valve (including associated 

safety equipment) on the last production facility on the OCS that do not 

connect to a transporter-operated pipeline on the OCS before crossing into 

State waters; 

(3) Producer-operated pipelines connecting production facilities on the 

OCS; 

(4) Transporter-operated pipelines 

that DOI and DOT have agreed are to 

be regulated as DOI pipelines; and 

(5) All OCS pipelines not subject to 

regulation under 49 CFR parts 192 and 

195. 

DOT pipelines include: 

(1) Transporter-operated pipelines 

currently operated under DOT requirements governing design, construction, 

maintenance, and operation; 

(2) Producer-operated pipelines that 

DOI and DOT have agreed are to be regulated under DOT requirements governing design, construction, maintenance, and operation; and 

(3) Producer-operated pipelines downstream (generally shoreward) of the 

last valve (including associated safety 

equipment) on the last production facility on the OCS that do not connect 

to a transporter-operated pipeline on 

the OCS before crossing into State 

waters and that are regulated under 49 

CFR parts 192 and 195. 

Lease term pipelines are those pipelines owned and operated by a lessee or 

operator and are wholly contained 

within the boundaries of a single lease, 

unitized leases, or contiguous (not cornering) leases of that lessee or operator. 

Out-of-service pipelines are those pipelines that have not been used to transport oil, natural gas, sulfur, or produced water for more than 30 consecutive days. 

Pipelines are the piping, risers, and 

appurtenances installed for the purpose 

of transporting oil, gas, sulphur, and 

produced water. (Piping confined to a 

production platform or structure is 

covered in Subpart H, Production Safety Systems, and is excluded from this 

subpart.) 

Production facilities means OCS facilities that receive hydrocarbon production either directly from wells or from 

other facilities that produce hydrocarbons from wells. They may include 

processing equipment for treating the 

production or separating it into its 

various liquid and gaseous components 

before transporting it to shore. 

Right-of-way pipelines are those pipelines which— 

(1) Are contained within the boundaries of a single lease or group of unitized leases but are not owned and operated by the lessee or operator of that 

lease or unit, 

(2) Are contained within the boundaries of contiguous (not cornering) 

leases which do not have a common lessee or operator, 

(3) Are contained within the boundaries of contiguous (not cornering) 

leases which have a common lessee or 

operator but are not owned and operated by that common lessee or operator, or 

(4) Cross any portion of an unleased 

block(s). 

§ 250.1002 Design requirements for 

DOI pipelines. 

(a) The internal design pressure for 

steel pipe shall be determined in accordance with the following formula: 

For limitations see section 841.121 of 

American National Standards Institute 

(ANSI) B31.8 (as incorporated by reference in §250.198) where— 

P = Internal design pressure in pounds per 

square inch (psi). 

S = Specified minimum yield strength, in 

psi, stipulated in the specification under 

which the pipe was purchased from the 

manufacturer or determined in accordance with section 811.253(h) of ANSI 

B31.8. 

D = Nominal outside diameter of pipe, in 

inches. 


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Safety & Environmental Enforcement, Interior § 250.1003 

t = Nominal wall thickness, in inches. 

F = Construction design factor of 0.72 for the 

submerged component and 0.60 for the 

riser component. 

E = Longitudinal joint factor obtained from 

Table 841.1B of ANSI B31.8 (see also section 811.253(d)). 

T = Temperature derating factor obtained 

from Table 841.1C of ANSI B31.8. 

(b)(1) Pipeline valves shall meet the 

minimum design requirements of 

American Petroleum Institute (API) 

Spec 6A (as incorporated by reference 

in §250.198), API Spec 6D (as incorporated by reference in §250.198), or the 

equivalent. A valve may not be used 

under operating conditions that exceed 

the applicable pressure-temperature 

ratings contained in those standards. 

(2) Pipeline flanges and flange accessories shall meet the minimum design 

requirements of ANSI B16.5, API Spec 

6A, or the equivalent (as incorporated 

by reference in 30 CFR 250.198). Each 

flange assembly must be able to withstand the maximum pressure at which 

the pipeline is to be operated and to 

maintain its physical and chemical 

properties at any temperature to which 

it is anticipated that it might be subjected in service. 

(3) Pipeline fittings shall have pressure-temperature ratings based on 

stresses for pipe of the same or equivalent material. The actual bursting 

strength of the fitting shall at least be 

equal to the computed bursting 

strength of the pipe. 

(4) If you are installing pipelines constructed of unbonded flexible pipe, you 

must design them according to the 

standards and procedures of API Spec 

17J, as incorporated by reference in 30 

CFR 250.198. 

(5) You must design pipeline risers 

for tension leg platforms and other 

floating platforms according to the design standards of API RP 2RD, Design 

of Risers for Floating Production Systems (FPSs) and Tension Leg Platforms (TLPs) (as incorporated by reference in §250.198). 

(c) The maximum allowable operating pressure (MAOP) shall not exceed 

the least of the following: 

(1) Internal design pressure of the 

pipeline, valves, flanges, and fittings; 

(2) Eighty percent of the hydrostatic 

pressure test (HPT) pressure of the 

pipeline; or 

(3) If applicable, the MAOP of the receiving pipeline when the proposed 

pipeline and the receiving pipeline are 

connected at a subsea tie-in. 

(d) If the maximum source pressure 

(MSP) exceeds the pipeline’s MAOP, 

you must install and maintain redundant safety devices meeting the requirements of section A9 of API RP 14C 

(as incorporated by reference in 

§250.198). Pressure safety valves (PSV) 

may be used only after a determination 

by the Regional Supervisor that the 

pressure will be relieved in a safe and 

pollution-free manner. The setting 

level at which the primary and redundant safety equipment actuates shall 

not exceed the pipeline’s MAOP. 

(e) Pipelines shall be provided with 

an external protective coating capable 

of minimizing underfilm corrosion and 

a cathodic protection system designed 

to mitigate corrosion for at least 20 

years. 

(f) Pipelines shall be designed and 

maintained to mitigate any reasonably 

anticipated detrimental effects of 

water currents, storm or ice scouring, 

soft bottoms, mud slides, earthquakes, 

subfreezing temperatures, and other 

environmental factors. 

§ 250.1003 Installation, testing, and repair requirements for DOI pipelines. 

(a)(1) Pipelines greater than 85⁄8

inches in diameter and installed in 

water depths of less than 200 feet shall 

be buried to a depth of at least 3 feet 

unless they are located in pipeline congested areas or seismically active areas 

as determined by the Regional Supervisor. Nevertheless, the Regional Supervisor may require burial of any 

pipeline if the Regional Supervisor determines that such burial will reduce 

the likelihood of environmental degradation or that the pipeline may constitute a hazard to trawling operations 

or other uses. A trawl test or diver survey may be required to determine 

whether or not pipeline burial is necessary or to determine whether a pipeline has been properly buried. 

(2) Pipeline valves, taps, tie-ins, 

capped lines, and repaired sections that 

could be obstructive shall be provided 

with at least 3 feet of cover unless the 

Regional Supervisor determines that 


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§ 250.1004 30 CFR Ch. II (7–1–13 Edition) 

such items present no hazard to trawling or other operations. A protective 

device may be used to cover an obstruction in lieu of burial if it is approved by the Regional Supervisor 

prior to installation. 

(3) Pipelines shall be installed with a 

minimum separation of 18 inches at 

pipeline crossings and from obstructions. 

(4) Pipeline risers installed after 

April 1, 1988, shall be protected from 

physical damage that could result from 

contact with floating vessels. Riser 

protection on pipelines installed on or 

before April 1, 1988, may be required 

when the Regional Supervisor determines that significant damage potential exists. 

(b)(1) Pipelines shall be pressure tested with water at a stabilized pressure 

of at least 1.25 times the MAOP for at 

least 8 hours when installed, relocated, 

uprated, or reactivated after being outof-service for more than 1 year. 

(2) Prior to returning a pipeline to 

service after a repair, the pipeline shall 

be pressure tested with water or processed natural gas at a minimum stabilized pressure of at least 1.25 times 

the MAOP for at least 2 hours. 

(3) Pipelines shall not be pressure 

tested at a pressure which produces a 

stress in the pipeline in excess of 95 

percent of the specified minimum-yield 

strength of the pipeline. A temperature 

recorder measuring test fluid temperature synchronized with a pressure recorder along with deadweight test 

readings shall be employed for all pressure testing. When a pipeline is pressure tested, no observable leakage shall 

be allowed. Pressure gauges and recorders shall be of sufficient accuracy to 

verify that leakage is not occurring. 

(4) The Regional Supervisor may require pressure testing of pipelines to 

verify the integrity of the system when 

the Regional Supervisor determines 

that there is a reasonable likelihood 

that the line has been damaged or 

weakened by external or internal conditions. 

(c) When a pipeline is repaired utilizing a clamp, the clamp shall be a full 

encirclement clamp able to withstand 

the anticipated pipeline pressure. 

§ 250.1004 Safety equipment requirements for DOI pipelines. 

(a) The lessee shall ensure the proper 

installation, operation, and maintenance of safety devices required by this 

section on all incoming, departing, and 

crossing pipelines on platforms. 

(b)(1)(i) Incoming pipelines to a platform shall be equipped with a flow safety valve (FSV). 

(ii) For sulphur operations, incoming 

pipelines delivering gas to the power 

plant platform may be equipped with 

high- and low-pressure sensors (PSHL), 

which activate audible and visual 

alarms in lieu of requirements in paragraph (b)(1)(i) of this section. The 

PSHL shall be set at 15 percent or 5 psi, 

whichever is greater, above and below 

the normal operating pressure range. 

(2) Incoming pipelines boarding a 

production platform shall be equipped 

with an automatic shutdown valve 

(SDV) immediately upon boarding the 

platform. The SDV shall be connected 

to the automatic- and remote-emergency shut-in systems. 

(3) Departing pipelines receiving production from production facilities shall 

be protected by high- and low-pressure 

sensors (PSHL) to directly or indirectly shut in all production facilities. 

The PSHL shall be set not to exceed 15 

percent above and below the normal 

operating pressure range. However, 

high pilots shall not be set above the 

pipeline’s MAOP. 

(4) Crossing pipelines on production 

or manned nonproduction platforms 

which do not receive production from 

the platform shall be equipped with an 

SDV immediately upon boarding the 

platform. The SDV shall be operated by 

a PSHL on the departing pipelines and 

connected to the platform automaticand remote-emergency shut-in systems. 

(5) The Regional Supervisor may require that oil pipelines be equipped 

with a metering system to provide a 

continuous volumetric comparison between the input to the line at the 

structure(s) and the deliveries onshore. 

The system shall include an alarm system and shall be of adequate sensitivity to detect variations between 

input and discharge volumes. In lieu of 

the foregoing, a system capable of detecting leaks in the pipeline may be 


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Safety & Environmental Enforcement, Interior § 250.1007 

substituted with the approval of the 

Regional Supervisor. 

(6) Pipelines incoming to a subsea 

tie-in shall be equipped with a block 

valve and an FSV. Bidirectional pipelines connected to a subsea tie-in shall 

be equipped with only a block valve. 

(7) Gas-lift or water-injection pipelines on unmanned platforms need only 

be equipped with an FSV installed immediately upstream of each casing annulus or the first inlet valve on the 

christmas tree. 

(8) Bidirectional pipelines shall be 

equipped with a PSHL and an SDV immediately upon boarding each platform. 

(9) Pipeline pumps must comply with 

section A7 of API RP 14C (as incorporated by reference in §250.198). The 

setting levels for the PSHL devices are 

specified in paragraph (b)(3) of this section. 

(c) If the required safety equipment 

is rendered ineffective or removed from 

service on pipelines which are continued in operation, an equivalent degree 

of safety shall be provided. The safety 

equipment shall be identified by the 

placement of a sign on the equipment 

stating that the equipment is rendered 

ineffective or removed from service. 

§ 250.1005 Inspection requirements for 

DOI pipelines. 

(a) Pipeline routes shall be inspected 

at time intervals and methods prescribed by the Regional Supervisor for 

indication of pipeline leakage. The results of these inspections shall be retained for at least 2 years and be made 

available to the Regional Supervisor 

upon request. 

(b) When pipelines are protected by 

rectifiers or anodes for which the initial life expectancy of the cathodic protection system either cannot be calculated or calculations indicate a life 

expectancy of less than 20 years, such 

pipelines shall be inspected annually 

by taking measurements of pipe-toelectrolyte potential. 

§ 250.1006 How must I decommission 

and take out of service a DOI pipeline? 

(a) The requirements for decommissioning pipelines are listed in §250.1750 

through §250.1754. 

(b) The table in this section lists the 

requirements if you take a DOI pipeline out of service: 

If you have the pipeline out of service for: Then you must: 

(1) 1 year or less, Isolate the pipeline with a blind flange or a closed block valve at each end of the 

pipeline. 

(2) More than 1 year but less than 5 years, Flush and fill the pipeline with inhibited seawater. 

(3) 5 or more years, Decommission the pipeline according to §§ 250.1750–250.1754. 

§ 250.1007 What to include in applications. 

(a) Applications to install a lease 

term pipeline or for a pipeline right-ofway grant must be submitted in quadruplicate to the Regional Supervisor. 

Right-of-way grant applications must 

include an identification of the operator of the pipeline. Each application 

must include the following: 

(1) Plat(s) drawn to a scale specified 

by the Regional Supervisor showing 

major features and other pertinent 

data including area, lease, and block 

designations; water depths; route; 

length in Federal waters; width of 

right-of-way, if applicable; connecting 

facilities; size; product(s) to be transported with anticipated gravity or density; burial depth; direction of flow; X– 

Y coordinates of key points; and the location of other pipelines that will be 

connected to or crossed by the proposed pipeline(s). The initial and terminal points of the pipeline and any 

continuation into State jurisdiction 

shall be accurately located even if the 

pipeline is to have an onshore terminal 

point. A plat(s) submitted for a pipeline right-of-way shall bear a signed 

certificate upon its face by the engineer who made the map that certifies 

that the right-of-way is accurately represented upon the map and that the design characteristics of the associated 

pipeline are in accordance with applicable regulations. 


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§ 250.1008 30 CFR Ch. II (7–1–13 Edition) 

(2) A schematic drawing showing the 

size, weight, grade, wall thickness, and 

type of line pipe and risers; pressureregulating devices (including backpressure regulators); sensing devices 

with associated pressure-control lines; 

PSV’s and settings; SDV’s, FSV’s, and 

block valves; and manifolds. This schematic drawing shall also show input 

source(s), e.g., wells, pumps, compressors, and vessels; maximum input pressure(s); the rated working pressure, as 

specified by ANSI or API, of all valves, 

flanges, and fittings; the initial receiving equipment and its rated working 

pressure; and associated safety equipment and pig launchers and receivers. 

The schematic must indicate the point 

on the OCS at which operating responsibility transfers between a producing 

operator and a transporting operator. 

(3) General information as follows: 

(i) Description of cathodic protection 

system. If pipeline anodes are to be 

used, specify the type, size, weight, 

number, spacing, and anticipated life; 

(ii) Description of external pipeline 

coating system; 

(iii) Description of internal protective measures; 

(iv) Specific gravity of the empty 

pipe; 

(v) MSP; 

(vi) MAOP and calculations used in 

its determination; 

(vii) Hydrostatic test pressure, medium, and period of time that the line 

will be tested; 

(viii) MAOP of the receiving pipeline 

or facility, 

(ix) Proposed date for commencing 

installation and estimated time for 

construction; and 

(x) Type of protection to be afforded 

crossing pipelines, subsea valves, taps, 

and manifold assemblies, if applicable. 

(4) A description of any additional design precautions you took to enable 

the pipeline to withstand the effects of 

water currents, storm or ice scouring, 

soft bottoms, mudslides, earthquakes, 

permafrost, and other environmental 

factors. 

(i) If you propose to use unbonded 

flexible pipe, your application must include: 

(A) The manufacturer’s design specification sheet; 

(B) The design pressure (psi); 

(C) An identification of the design 

standards you used; and 

(D) A review by a third-party independent verification agent (IVA) according to API Spec 17J (as incorporated by reference in §250.198), if applicable. 

(ii) If you propose to use one or more 

pipeline risers for a tension leg platform or other floating platform, your 

application must include: 

(A) The design fatigue life of the 

riser, with calculations, and the fatigue point at which you would replace 

the riser; 

(B) The results of your vortex-induced vibration (VIV) analysis; 

(C) An identification of the design 

standards you used; and 

(D) A description of any necessary 

mitigation measures such as the use of 

helical strakes or anchoring devices. 

(5) The application shall include a 

shallow hazards survey report and, if 

required by the Regional Director, an 

archaeological resource report that 

covers the entire length of the pipeline. 

A shallow hazards analysis may be included in a lease term pipeline application in lieu of the shallow hazards survey report with the approval of the Regional Director. The Regional Director 

may require the submission of the data 

upon which the report or analysis is 

based. 

(b) Applications to modify an approved lease term pipeline or right-ofway grant shall be submitted in quadruplicate to the Regional Supervisor. 

These applications need only address 

those items in the original application 

affected by the proposed modification. 

§ 250.1008 Reports. 

(a) The lessee, or right-of-way holder, 

shall notify the Regional Supervisor at 

least 48 hours prior to commencing the 

installation or relocation of a pipeline 

or conducting a pressure test on a pipeline. 

(b) The lessee or right-of-way holder 

shall submit a report to the Regional 

Supervisor within 90 days after completion of any pipeline construction. The 

report, submitted in triplicate, shall 

include an ‘‘as-built’’ location plat 

drawn to a scale specified by the Regional Supervisor showing the location, length in Federal waters, and X– 


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Safety & Environmental Enforcement, Interior § 250.1010 

Y coordinates of key points; the completion date; the proposed date of first 

operation; and the HPT data. Pipeline 

right-of-way ‘‘as-built’’ location plats 

shall be certified by a registered engineer or land surveyor and show the 

boundaries of the right-of-way as 

granted. If there is a substantial deviation of the pipeline route as granted 

in the right-of-way, the report shall include a discussion of the reasons for 

such deviation. 

(c) The lessee or right-of-way holder 

shall report to the Regional Supervisor 

any pipeline taken out of service. If the 

period of time in which the pipeline is 

out of service is greater than 60 days, 

written confirmation is also required. 

(d) The lessee or right-of-way holder 

shall report to the Regional Supervisor 

when any required pipeline safety 

equipment is taken out of service for 

more than 12 hours. The Regional Supervisor shall be notified when the 

equipment is returned to service. 

(e) The lessee or right-of-way holder 

must notify the Regional Supervisor 

before the repair of any pipeline or as 

soon as practicable. Your notification 

must be accompanied by payment of 

the service fee listed in §250.125. You 

must submit a detailed report of the 

repair of a pipeline or pipeline component to the Regional Supervisor within 

30 days after the completion of the repairs. In the report you must include 

the following: 

(1) Description of repairs; 

(2) Results of pressure test; and 

(3) Date returned to service. 

(f) The Regional Supervisor may require that DOI pipeline failures be analyzed and that samples of a failed section be examined in a laboratory to assist in determining the cause of the 

failure. A comprehensive written report of the information obtained shall 

be submitted by the lessee to the Regional Supervisor as soon as available. 

(g) If the effects of scouring, soft bottoms, or other environmental factors 

are observed to be detrimentally affecting a pipeline, a plan of corrective 

action shall be submitted to the Regional Supervisor for approval within 

30 days of the observation. A report of 

the remedial action taken shall be submitted to the Regional Supervisor by 

the lessee or right-of-way holder within 

30 days after completion. 

(h) The results and conclusions of 

measurements of pipe-to-electrolyte 

potential measurements taken annually on DOI pipelines in accordance 

with §250.1005(b) of this part shall be 

submitted to the Regional Supervisor 

by the lessee before March of each 

year. 

§ 250.1009 Requirements to obtain 

pipeline right-of-way grants. 

(a) In addition to applicable requirements of §§250.1000 through 250.1008 and 

other regulations of this part, regulations of the Department of Transportation, Department of the Army, and 

the Federal Energy Regulatory Commission (FERC), when a pipeline qualifies as a right-of-way pipeline, the 

pipeline shall not be installed until a 

right-of-way has been requested and 

granted in accordance with this subpart. The right-of-way grant is issued 

pursuant to 43 U.S.C. 1334(e) and may 

be acquired and held only by citizens 

and nationals of the United States; 

aliens lawfully admitted for permanent 

residence in the United States as defined in 8 U.S.C. 1101(a)(20); private, 

public, or municipal corporations organized under the laws of the United 

States or territory thereof, the District 

of Columbia, or of any State; or associations of such citizens, nationals, 

resident aliens, or private, public, or 

municipal corporations, States, or political subdivisions of States. 

(b) A right-of-way shall include the 

site on which the pipeline and associated structures are to be situated, shall 

not exceed 200 feet in width unless safety and environmental factors during 

construction and operation of the associated right-of-way pipeline require a 

greater width, and shall be limited to 

the area reasonably necessary for 

pumping stations or other accessory 

structures. 

§ 250.1010 General requirements for 

pipeline right-of-way holders. 

An applicant, by accepting a right-ofway grant, agrees to comply with the 

following requirements: 

(a) The right-of-way holder shall 

comply with applicable laws and regulations and the terms of the grant. 


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§ 250.1011 30 CFR Ch. II (7–1–13 Edition) 

(b) The granting of the right-of-way 

shall be subject to the express condition that the rights granted shall not 

prevent or interfere in any way with 

the management, administration, or 

the granting of other rights by the 

United States, either prior or subsequent to the granting of the right-ofway. Moreover, the holder agrees to 

allow the occupancy and use by the 

United States, its lessees, or other 

right-of-way holders, of any part of the 

right-of-way grant not actually occupied or necessarily incident to its use 

for any necessary operations involved 

in the management, administration, or 

the enjoyment of such other granted 

rights. 

(c) If the right-of-way holder discovers any archaeological resource 

while conducting operations within the 

right-of-way, the right-of-way holder 

shall immediately halt operations 

within the area of the discovery and report the discovery to the Regional Director. If investigations determine that 

the resource is significant, the Regional Director will inform the rightof-way holder how to protect it. 

(d) The Regional Supervisor shall be 

kept informed at all times of the rightof-way holder’s address and, if a corporation, the address of its principal 

place of business and the name and address of the officer or agent authorized 

to be served with process. 

(e) The right-of-way holder shall pay 

the United States or its lessees or 

right-of-way holders, as the case may 

be, the full value of all damages to the 

property of the United States or its 

said lessees or right-of-way holders and 

shall indemnify the United States 

against any and all liability for damages to life, person, or property arising 

from the occupation and use of the 

area covered by the right-of-way grant. 

(f)(1) The holder of a right-of-way oil 

or gas pipeline shall transport or purchase oil or natural gas produced from 

submerged lands in the vicinity of the 

pipeline without discrimination and in 

such proportionate amounts as the 

FERC may, after a full hearing with 

due notice thereof to the interested 

parties, determine to be reasonable, 

taking into account, among other 

things, conservation and the prevention of waste. 

(2) Unless otherwise exempted by 

FERC pursuant to 43 U.S.C. 1334(f)(2), 

the holder shall: 

(i) Provide open and nondiscriminatory access to a right-of-way pipeline to both owner and nonowner shippers, and 

(ii) Comply with the provisions of 43 

U.S.C. 1334(f)(1)(B) under which FERC 

may order an expansion of the throughput capacity of a right-of-way pipeline 

which is approved after September 18, 

1978, and which is not located in the 

Gulf of Mexico or the Santa Barbara 

Channel. 

(g) The area covered by a right-ofway and all improvements thereon 

shall be kept open at all reasonable 

times for inspection by the Bureau of 

Safety and Environmental Enforcement (BSEE). The right-of-way holder 

shall make available all records relative to the design, construction, operation, maintenance and repair, and investigations on or with regard to such 

area. 

(h) Upon relinquishment, forfeiture, 

or cancellation of a right-of-way grant, 

the right-of-way holder shall remove 

all platforms, structures, domes over 

valves, pipes, taps, and valves along 

the right-of-way. All of these improvements shall be removed by the holder 

within 1 year of the effective date of 

the relinquishment, forfeiture, or cancellation unless this requirement is 

waived in writing by the Regional Supervisor. All such improvements not 

removed within the time provided 

herein shall become the property of the 

United States but that shall not relieve 

the holder of liability for the cost of 

their removal or for restoration of the 

site. Furthermore, the holder is responsible for accidents or damages which 

might occur as a result of failure to 

timely remove improvements and 

equipment and restore a site. An application for relinquishment of a right-ofway grant shall be filed in accordance 

with §250.1019 of this part. 

§ 250.1011 [Reserved] 

§ 250.1012 Required payments for pipeline right-of-way holders. 

(a) You must pay ONRR, under the 

regulations at 30 CFR part 1218, an annual rental of $15 for each statute mile, 


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Safety & Environmental Enforcement, Interior § 250.1015 

or part of a statute mile, of the OCS 

that your pipeline right-of-way crosses. 

(b) This paragraph applies to you if 

you obtain a pipeline right-of-way that 

includes a site for an accessory to the 

pipeline, including but not limited to a 

platform. This paragraph also applies if 

you apply to modify a right-of-way to 

change the site footprint. In either 

case, you must pay the amounts shown 

in the following table. 

If . . . Then . . . 

(1) Your accessory site is located in water 

depths of less than 200 meters; 

You must pay ONRR, under the regulations at 30 CFR part 1218, a rental of $5 

per acre per year with a minimum of $450 per year. The area subject to annual 

rental includes the areal extent of anchor chains, pipeline risers, and other facilities and devices associated with the accessory. 

(2) Your accessory site is located in water 

depths of 200 meters or greater; 

You must pay ONRR, under the regulations at 30 CFR part 1218, a rental of $7.50 

per acre per year with a minimum of $675 per year. The area subject to annual 

rental includes the areal extent of anchor chains, pipeline risers, and other facilities and devices associated with the accessory. 

(c) If you hold a pipeline right-of-way 

that includes a site for an accessory to 

your pipeline and you are not covered 

by paragraph (b) of this section, then 

you must pay ONRR, under the regulations at 30 CFR part 1218, an annual 

rental of $75 for use of the affected 

area. 

(d) You may make the rental payments required by paragraphs (a), 

(b)(1), (b)(2), and (c) of this section on 

an annual basis, for a 5-year period, or 

for multiples of 5 years. You must 

make the first payment at the time 

you submit the pipeline right-of-way 

application. You must make all subsequent payments before the respective 

time periods begin. 

(e) Late payments. An interest charge 

will be assessed on unpaid and underpaid amounts from the date the 

amounts are due, in accordance with 

the provisions found in 30 CFR 1218.54. 

If you fail to make a payment that is 

late after written notice from ONRR, 

BSEE may initiate cancellation of the 

right-of-use grant and easement under 

§250.1013. 

§ 250.1013 Grounds for forfeiture of 

pipeline right-of-way grants. 

Failure to comply with the Act, regulations, or any conditions of the rightof-way grant prescribed by the Regional Supervisor shall be grounds for 

forfeiture of the grant in an appropriate judicial proceeding instituted by 

the United States in any U.S. District 

Court having jurisdiction in accordance with the provisions of 43 U.S.C. 

1349. 

§ 250.1014 When pipeline right-of-way 

grants expire. 

Any right-of-way granted under the 

provisions of this subpart remains in 

effect as long as the associated pipeline 

is properly maintained and used for the 

purpose for which the grant was made, 

unless otherwise expressly stated in 

the grant. Temporary cessation or suspension of pipeline operations shall not 

cause the grant to expire. However, if 

the purpose of the grant ceases to exist 

or use of the associated pipeline is permanently discontinued for any reason, 

the grant shall be deemed to have expired. 

§ 250.1015 Applications for pipeline 

right-of-way grants. 

(a) You must submit an original and 

three copies of an application for a new 

or modified pipeline ROW grant to the 

Regional Supervisor. The application 

must address those items required by 

§250.1007(a) or (b) of this subpart, as applicable. It must also state the primary 

purpose for which you will use the 

ROW grant. If the ROW has been used 

before the application is made, the application must state the date such use 

began, by whom, and the date the applicant obtained control of the improvement. When you file your application, you must pay the rental required 

under §250.1012 of this subpart, as well 

as the service fees listed in §250.125 of 

this part for a pipeline ROW grant to 

install a new pipeline, or to convert an 

existing lease term pipeline into a 


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§ 250.1016 30 CFR Ch. II (7–1–13 Edition) 

ROW pipeline. An application to modify an approved ROW grant must be accompanied by the additional rental required under §250.1012 if applicable. 

You must file a separate application 

for each ROW. 

(b)(1) An individual applicant shall 

submit a statement of citizenship or 

nationality with the application. An 

applicant who is an alien lawfully admitted for permanent residence in the 

United States shall also submit evidence of such status with the application. 

(2) If the applicant is an association 

(including a partnership), the application shall also be accompanied by a 

certified copy of the articles of association or appropriate reference to a copy 

of such articles already filed with 

BSEE and a statement as to any subsequent amendments. 

(3) If the applicant is a corporation, 

the application shall also include the 

following: 

(i) A statement certified by the Secretary or Assistant Secretary of the 

corporation with the corporate seal 

showing the State in which it is incorporated and the name of the person(s) 

authorized to act on behalf of the corporation, or 

(ii) In lieu of such a statement, an 

appropriate reference to statements or 

records previously submitted to BSEE 

(including material submitted in compliance with prior regulations). 

(c) The application shall include a 

list of every lessee and right-of-way 

holder whose lease or right-of-way is 

intersected by the proposed right-ofway. The application shall also include 

a statement that a copy of the application has been sent by registered or certified mail to each such lessee or rightof-way holder. 

(d) The applicant shall include in the 

application an original and three copies of a completed Nondiscrimination 

in Employment form (YN 3341–1 dated 

July 1982). These forms are available at 

each BSEE regional office. 

(e) Notwithstanding the provisions of 

paragraph (a) of this section, the requirements to pay filing fees under 

that paragraph are suspended until 

January 3, 2006. 

§ 250.1016 Granting pipeline rights-ofway. 

(a) In considering an application for a 

right-of-way, the Regional Supervisor 

shall consider the potential effect of 

the associated pipeline on the human, 

marine, and coastal environments, life 

(including aquatic life), property, and 

mineral resources in the entire area 

during construction and operational 

phases. The Regional Supervisor shall 

prepare an environmental analysis in 

accordance with applicable policies and 

guidelines. To aid in the evaluation 

and determinations, the Regional Supervisor may request and consider 

views and recommendations of appropriate Federal Agencies, hold public 

meetings after appropriate notice, and 

consult, as appropriate, with State 

agencies, organizations, industries, and 

individuals. Before granting a pipeline 

right-of-way, the Regional Supervisor 

shall give consideration to any recommendation by the intergovernmental planning program, or similar 

process, for the assessment and management of OCS oil and gas transportation. 

(b) Should the proposed route of a 

right-of-way adjoin and subsequently 

cross any State submerged lands, the 

applicant shall submit evidence to the 

Regional Supervisor that the State(s) 

so affected has reviewed the application. The applicant shall also submit 

any comment received as a result of 

that review. In the event of a State 

recommendation to relocate the proposed route, the Regional Supervisor 

may consult with the appropriate 

State officials. 

(c)(1) The applicant shall submit photocopies of return receipts to the Regional Supervisor that indicate the 

date that each lessee or right-of-way 

holder referenced in §250.1015(c) of this 

part has received a copy of the application. Letters of no objection may be 

submitted in lieu of the return receipts. 

(2) The Regional Supervisor shall not 

take final action on a right-of-way application until the Regional Supervisor 

is satisfied that each such lessee or 

right-of-way holder has been afforded 

at least 30 days from the date determined in paragraph (c)(1) of this section in which to submit comments. 


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Safety & Environmental Enforcement, Interior § 250.1018 

(d) If a proposed right-of-way crosses 

any lands not subject to disposition by 

mineral leasing or restricted from oil 

and gas activities, it shall be rejected 

by the Regional Supervisor unless the 

Federal Agency with jurisdiction over 

such excluded or restricted area gives 

its consent to the granting of the 

right-of-way. In such case, the applicant, upon a request filed within 30 

days after receipt of the notification of 

such rejection, shall be allowed an opportunity to eliminate the conflict. 

(e)(1) If the application and other required information are found to be in 

compliance with applicable laws and 

regulations, the right-of-way may be 

granted. The Regional Supervisor may 

prescribe, as conditions to the right-ofway grant, stipulations necessary to 

protect human, marine, and coastal environments, life (including aquatic 

life), property, and mineral resources 

located on or adjacent to the right-ofway. 

(2) If the Regional Supervisor determines that a change in the application 

should be made, the Regional Supervisor shall notify the applicant that an 

amended application shall be filed subject to stipulated changes. The Regional Supervisor shall determine 

whether the applicant shall deliver 

copies of the amended application to 

other parties for comment. 

(3) A decision to reject an application 

shall be in writing and shall state the 

reasons for the rejection. 

§ 250.1017 Requirements for construction under pipeline right-of-way 

grants. 

(a) Failure to construct the associated right-of-way pipeline within 5 

years of the date of the granting of a 

right-of-way shall cause the grant to 

expire. 

(b)(1) A right-of-way holder shall ensure that the right-of-way pipeline is 

constructed in a manner that minimizes deviations from the right-of-way 

as granted. 

(2) If, after constructing the right-ofway pipeline, it is determined that a 

deviation from the proposed right-ofway as granted has occurred, the rightof-way holder shall— 

(i) Notify the operators of all leases 

and holders of all right-of-way grants 

in which a deviation has occurred, and 

within 60 days of the date of the acceptance by the Regional Supervisor of 

the completion of pipeline construction 

report, provide the Regional Supervisor 

with evidence of such notification; and 

(ii) Relinquish any unused portion of 

the right-of-way. 

(3) Substantial deviation of a rightof-way pipeline as constructed from the 

proposed right-of-way as granted may 

be grounds for forfeiture of the rightof-way. 

(c) If the Regional Supervisor determines that a significant change in conditions has occurred subsequent to the 

granting of a right-of-way but prior to 

the commencement of construction of 

the associated pipeline, the Regional 

Supervisor may suspend or temporarily 

prohibit the commencement of construction until the right-of-way grant 

is modified to the extent necessary to 

address the changed conditions. 

§ 250.1018 Assignment of pipeline 

right-of-way grants. 

(a) Assignment may be made of a 

right-of-way grant, in whole or of any 

lineal segment thereof, subject to the 

approval of the Regional Supervisor. 

An application for approval of an assignment of a right-of-way or of a lineal segment thereof, shall be filed in 

triplicate with the Regional Supervisor. 

(b) Any application for approval for 

an assignment, in whole or in part, of 

any right, title, or interest in a rightof-way grant must be accompanied by 

the same showing of qualifications of 

the assignees as is required of an applicant for a ROW in §250.1015 of this subpart and must be supported by a statement that the assignee agrees to comply with and to be bound by the terms 

and conditions of the ROW grant. The 

assignee must satisfy the bonding requirements in 30 CFR 550.1011. No 

transfer will be recognized unless and 

until it is first approved, in writing, by 

the Regional Supervisor. The assignee 

must pay the service fee listed in 

§250.125 of this part for a pipeline ROW 

assignment request. 

(c) Notwithstanding the provisions of 

paragraph (b) of this section, the requirement to pay a filing fee under 


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§ 250.1019 30 CFR Ch. II (7–1–13 Edition) 

that paragraph is suspended until January 3, 2006. 

§ 250.1019 Relinquishment of pipeline 

right-of-way grants. 

A right-of-way grant or a portion 

thereof may be surrendered by the 

holder by filing a written relinquishment in triplicate with the Regional 

Supervisor. It must contain those 

items addressed in §§250.1751 and 

250.1752 of this part. A relinquishment 

shall take effect on the date it is filed 

subject to the satisfaction of all outstanding debts, fees, or fines and the 

requirements in §250.1010(h) of this 

part. 

Subpart K—Oil and Gas 

Production Requirements 

GENERAL

§ 250.1150 What are the general reservoir production requirements? 

You must produce wells and reservoirs at rates that provide for economic development while maximizing 

ultimate recovery and without adversely affecting correlative rights. 

WELL TESTS AND SURVEYS

§ 250.1151 How often must I conduct 

well production tests? 

(a) You must conduct well production 

tests as shown in the following table: 

You must conduct: And you must submit to the Regional Supervisor: 

(1) A well-flow potential test on all new, recompleted, or reworked well completions within 30 days of the date of first 

continuous production, 

Form BSEE–0126, Well Potential Test Report, along with the 

supporting data as listed in the table in § 250.1167, within 15 

days after the end of the test period. 

(2) At least one well test during a calendar half-year for each 

producing completion, 

Results on Form BSEE–0128, Semiannual Well Test Report, 

of the most recent well test obtained. This must be submitted within 45 days after the end of the calendar half-year. 

(b) You may request an extension 

from the Regional Supervisor if you 

cannot submit the results of a semiannual well test within the specified 

time. 

(c) You must submit to the Regional 

Supervisor an original and two copies 

of the appropriate form required by 

paragraph (a) of this section; one of the 

copies of the form must be a public information copy in accordance with 

§§250.186 and 250.197, and marked ‘‘Public Information.’’ You must submit two 

copies of the supporting information as 

listed in the table in §250.1167 with 

form BSEE–0126. 

§ 250.1152 How do I conduct well tests? 

(a) When you conduct well tests you 

must: 

(1) Recover fluid from the well completion equivalent to the amount of 

fluid introduced into the formation 

during completion, recompletion, reworking, or treatment operations before you start a well test; 

(2) Produce the well completion 

under stabilized rate conditions for at 

least 6 consecutive hours before beginning the test period; 

(3) Conduct the test for at least 4 

consecutive hours; 

(4) Adjust measured gas volumes to 

the standard conditions of 14.73 pounds 

per square inch absolute (psia) and 60 

°F for all tests; and 

(5) Use measured specific gravity values to calculate gas volumes. 

(b) You may request approval from 

the Regional Supervisor to conduct a 

well test using alternative procedures 

if you can demonstrate test reliability 

under those procedures. 

(c) The Regional Supervisor may also 

require you to conduct the following 

tests and complete them within a specified time period: 

(1) A retest or a prolonged test of a 

well completion if it is determined to 

be necessary for the proper establishment of a Maximum Production Rate 

(MPR) or a Maximum Efficient Rate 

(MER); and 

(2) A multipoint back-pressure test 

to determine the theoretical open-flow 

potential of a gas well. 

(d) A BSEE representative may witness any well test. Upon request, you 

must provide advance notice to the Regional Supervisor of the times and 

dates of well tests. 


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Safety & Environmental Enforcement, Interior § 250.1158 

§§ 250.1153–250.1155 [Reserved] 

APPROVALS PRIOR TO PRODUCTION

§ 250.1156 What steps must I take to 

receive approval to produce within 

500 feet of a unit or lease line? 

(a) You must obtain approval from 

the Regional Supervisor before you 

start producing from a reservoir within 

a well that has any portion of the completed interval less than 500 feet from a 

unit or lease line. Submit to BSEE the 

service fee listed in §250.125, according 

to the instructions in §250.126, and the 

supporting information, as listed in the 

table in §250.1167, with your request. 

The Regional Supervisor will determine whether approval of your request 

will maximize ultimate recovery, avoid 

the waste of natural resources, or protect correlative rights. You do not need 

to obtain approval if the adjacent 

leases or units have the same unit, 

lease (record title and operating 

rights), and royalty interests as the 

lease or unit you plan to produce. You 

do not need to obtain approval if the 

adjacent block is unleased. 

(b) You must notify the operator(s) of 

adjacent property(ies) that are within 

500 feet of the completion, if the adjacent acreage is a leased block in the 

Federal OCS. You must provide the Regional Supervisor proof of the date of 

the notification. The operators of the 

adjacent properties have 30 days after 

receiving the notification to provide 

the Regional Supervisor letters of acceptance or objection. If an adjacent 

operator does not respond within 30 

days, the Regional Supervisor will presume there are no objections and proceed with a decision. The notification 

must include: 

(1) The well name; 

(2) The rectangular coordinates (x, y) 

of the location of the top and bottom of 

the completion or target completion 

referenced to the North American 

Datum 1983, and the subsea depths of 

the top and bottom of the completion 

or target completion; 

(3) The distance from the completion 

or target completion to the unit or 

lease line at its nearest point; and 

(4) A statement indicating whether 

or not it will be a high-capacity completion having a perforated or open 

hole interval greater than 150 feet 

measured depth. 

§ 250.1157 How do I receive approval 

to produce gas-cap gas from an oil 

reservoir with an associated gas 

cap? 

(a) You must request and receive approval from the Regional Supervisor: 

(1) Before producing gas-cap gas from 

each completion in an oil reservoir 

that is known to have an associated 

gas cap. 

(2) To continue production from a 

well if the oil reservoir is not initially 

known to have an associated gas cap, 

but the oil well begins to show characteristics of a gas well. 

(b) For either request, you must submit the service fee listed in §250.125, 

according to the instructions in 

§250.126, and the supporting information, as listed in the table in §250.1167, 

with your request. 

(c) The Regional Supervisor will determine whether your request maximizes ultimate recovery. 

§ 250.1158 How do I receive approval 

to downhole commingle hydrocarbons? 

(a) Before you perforate a well, you 

must request and receive approval from 

the Regional Supervisor to commingle 

hydrocarbons produced from multiple 

reservoirs within a common wellbore. 

The Regional Supervisor will determine whether your request maximizes 

ultimate recovery. You must include 

the service fee listed in §250.125, according to the instructions in §250.126, 

and the supporting information, as listed in the table in §250.1167, with your 

request. 

(b) If one or more of the reservoirs 

proposed for commingling is a competitive reservoir, you must notify the operators of all leases that contain the 

reservoir that you intend to downhole 

commingle the reservoirs. Your request 

for approval of downhole commingling 

must include proof of the date of this 

notification. The notified operators 

have 30 days after notification to provide the Regional Supervisor with letters of acceptance or objection. If the 

notified operators do not respond within the specified period, the Regional 

Supervisor will assume the operators 


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§ 250.1159 30 CFR Ch. II (7–1–13 Edition) 

do not object and proceed with a decision. 

PRODUCTION RATES

§ 250.1159 May the Regional Supervisor limit my well or reservoir production rates? 

(a) The Regional Supervisor may set 

a Maximum Production Rate (MPR) for 

a producing well completion, or set a 

Maximum Efficient Rate (MER) for a 

reservoir, or both, if the Regional Supervisor determines that an excessive 

production rate could harm ultimate 

recovery. An MPR or MER will be 

based on well tests and any limitations 

imposed by well and surface equipment, sand production, reservoir sensitivity, gas-oil and water-oil ratios, location of perforated intervals, and prudent operating practices. 

(b) If the Regional Supervisor sets an 

MPR for a producing well completion 

and/or an MER for a reservoir, you may 

not exceed those rates except due to 

normal variations and fluctuations in 

production rates as set by the Regional 

Supervisor. 

FLARING, VENTING, AND BURNING

HYDROCARBONS

§ 250.1160 When may I flare or vent 

gas? 

(a) You must request and receive approval from the Regional Supervisor to 

flare or vent natural gas at your facility, except in the following situations: 

Condition Additional requirements 

(1) When the gas is lease use gas (produced natural gas 

which is used on or for the benefit of lease operations such 

as gas used to operate production facilities) or is used as an 

additive necessary to burn waste products, such as H2S.

The volume of gas flared or vented may not exceed the 

amount necessary for its intended purpose. Burning waste 

products may require approval under other regulations. 

(2) During the restart of a facility that was shut in because of 

weather conditions, such as a hurricane.

Flaring or venting may not exceed 48 cumulative hours without 

Regional Supervisor approval. 

(3) During the blow down of transportation pipelines downstream of the royalty meter.(i) You must report the location, time, flare/vent volume, and 

reason for flaring/venting to the Regional Supervisor in writing within 72 hours after the incident is over. 

(ii) Additional approval may be required under subparts H and 

J of this part. 

(4) During the unloading or cleaning of a well, drill-stem testing, production testing, other well-evaluation testing, or the 

necessary blow down to perform these procedures.

You may not exceed 48 cumulative hours of flaring or venting 

per unloading or cleaning or testing operation on a single 

completion without Regional Supervisor approval. 

(5) When properly working equipment yields flash gas (natural 

gas released from liquid hydrocarbons as a result of a decrease in pressure, an increase in temperature, or both) from 

storage vessels or other low-pressure production vessels, 

and you cannot economically recover this flash gas.

You may not flare or vent more than an average of 50 MCF 

per day during any calendar month without Regional Supervisor approval. 

(6) When the equipment works properly but there is a temporary upset condition, such as a hydrate or paraffin plug.(i) For oil-well gas and gas-well flash gas (natural gas released 

from condensate as a result of a decrease in pressure, an 

increase in temperature, or both), you may not exceed 48 

continuous hours of flaring or venting without Regional Supervisor approval. 

(ii) For primary gas-well gas (natural gas from a gas well completion that is at or near its wellhead pressure; this does not 

include flash gas), you may not exceed 2 continuous hours 

of flaring or venting without Regional Supervisor approval. 

(iii) You may not exceed 144 cumulative hours of flaring or 

venting during a calendar month without Regional Supervisor 

approval. 

(7) When equipment fails to work properly, during equipment 

maintenance and repair, or when you must relieve system 

pressures.

(i) For oil-well gas and gas-well flash gas, you may not exceed 

48 continuous hours of flaring or venting without Regional 

Supervisor approval. 

(ii) For primary gas-well gas, you may not exceed 2 continuous 

hours of flaring or venting without Regional Supervisor approval. 

(iii) You may not exceed 144 cumulative hours of flaring or 

venting during a calendar month without Regional Supervisor 

approval. 

(iv) The continuous and cumulative hours allowed under this 

paragraph may be counted separately from the hours under 

paragraph (a)(6) of this section. 


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Safety & Environmental Enforcement, Interior § 250.1163 

(b) Regardless of the requirements in 

paragraph (a) of this section, you must 

not flare or vent gas over the volume 

approved in your Development Operations Coordination Document (DOCD) 

or your Development and Production 

Plan (DPP) submitted to BOEM. 

(c) The Regional Supervisor may establish alternative approval procedures 

to cover situations when you cannot 

contact the BSEE office, such as during non-office hours. 

(d) The Regional Supervisor may 

specify a volume limit, or a shorter 

time limit than specified elsewhere in 

this part, in order to prevent air quality degradation or loss of reserves. 

(e) If you flare or vent gas without 

the required approval, or if the Regional Supervisor determines that you 

were negligent or could have avoided 

flaring or venting the gas, the hydrocarbons will be considered avoidably 

lost or wasted. You must pay royalties 

on the loss or waste, according to 30 

CFR part 1202. You must value any gas 

or liquid hydrocarbons avoidably lost 

or wasted under the provisions of 30 

CFR part 1206. 

(f) Fugitive emissions from valves, 

fittings, flanges, pressure relief valves 

or similar components do not require 

approval under this subpart unless specifically required by the Regional Supervisor. 

§ 250.1161 When may I flare or vent 

gas for extended periods of time? 

You must request and receive approval from the Regional Supervisor to 

flare or vent gas for an extended period 

of time. The Regional Supervisor will 

specify the approved period of time, 

which will not exceed 1 year. The Regional Supervisor may deny your request if it does not ensure the conservation of natural resources or is not 

consistent with National interests relating to development and production 

of minerals of the OCS. The Regional 

Supervisor may approve your request 

for one of the following reasons: 

(a) You initiated an action which, 

when completed, will eliminate flaring 

and venting; or 

(b) You submit to the Regional Supervisor an evaluation supported by engineering, geologic, and economic data 

indicating that the oil and gas produced from the well(s) will not economically support the facilities necessary to sell the gas or to use the gas 

on or for the benefit of the lease. 

§ 250.1162 When may I burn produced 

liquid hydrocarbons? 

(a) You must request and receive approval from the Regional Supervisor to 

burn any produced liquid hydrocarbons. The Regional Supervisor may 

allow you to burn liquid hydrocarbons 

if you demonstrate that transporting 

them to market or re-injecting them is 

not technically feasible or poses a significant risk of harm to offshore personnel or the environment. 

(b) If you burn liquid hydrocarbons 

without the required approval, or if the 

Regional Supervisor determines that 

you were negligent or could have 

avoided burning liquid hydrocarbons, 

the hydrocarbons will be considered 

avoidably lost or wasted. You must pay 

royalties on the loss or waste, according to 30 CFR part 1202. You must value 

any liquid hydrocarbons avoidably lost 

or wasted under the provisions of 30 

CFR part 1206. 

§ 250.1163 How must I measure gas 

flaring or venting volumes and liquid hydrocarbon burning volumes, 

and what records must I maintain? 

(a) If your facility processes more 

than an average of 2,000 bopd during 

May 2010, you must install flare/vent 

meters within 180 days after May 2010. 

If your facility processes more than an 

average of 2,000 bopd during a calendar 

month after May 2010, you must install 

flare/vent meters within 120 days after 

the end of the month in which the average amount of oil processed exceeds 

2,000 bopd. 

(1) You must notify the Regional Supervisor when your facility begins to 

process more than an average of 2,000 

bopd in a calendar month; 

(2) The flare/vent meters must measure all flared and vented gas within 5 

percent accuracy; 

(3) You must calibrate the meters 

regularly, in accordance with the manufacturer’s recommendation, or at 

least once every year, whichever is 

shorter; and 


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§ 250.1164 30 CFR Ch. II (7–1–13 Edition) 

(4) You must use and maintain the 

flare/vent meters for the life of the facility. 

(b) You must report all hydrocarbons 

produced from a well completion, including all gas flared, gas vented, and 

liquid hydrocarbons burned, to Office 

of Natural Resources Revenue on Form 

ONRR–4054 (Oil and Gas Operations Report), in accordance with 30 CFR 

1210.102. 

(1) You must report the amount of 

gas flared and the amount of gas vented separately. 

(2) You may classify and report gas 

used to operate equipment on the lease, 

such as gas used to power engines, instrument gas, and gas used to maintain 

pilot lights, as lease use gas. 

(3) If flare/vent meters are required 

at one or more of your facilities, you 

must report the amount of gas flared 

and vented at each of those facilities 

separately from those facilities that do 

not require meters and separately from 

other facilities with meters. 

(4) If flare/vent meters are not required at your facility: 

(i) You may report the gas flared and 

vented on a lease or unit basis. Gas 

flared and vented from multiple facilities on a single lease or unit may be reported together. 

(ii) If you choose to install meters, 

you may report the gas volume flared 

and vented according to the method 

specified in paragraph (b)(3) of this section. 

(c) You must prepare and maintain 

records detailing gas flaring, gas venting, and liquid hydrocarbon burning for 

each facility for 6 years. 

(1) You must maintain these records 

on the facility for at least the first 2 

years and have them available for inspection by BSEE representatives. 

(2) After 2 years, you must maintain 

the records, allow BSEE representatives to inspect the records upon request and provide copies to the Regional Supervisor upon request, but are 

not required to keep them on the facility. 

(3) The records must include, at a 

minimum: 

(i) Daily volumes of gas flared, gas 

vented, and liquid hydrocarbons 

burned; 

(ii) Number of hours of gas flaring, 

gas venting, and liquid hydrocarbon 

burning, on a daily and monthly cumulative basis; 

(iii) A list of the wells contributing 

to gas flaring, gas venting, and liquid 

hydrocarbon burning, along with gasoil ratio data; 

(iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon burning; 

and 

(v) Documentation of all required approvals. 

(d) If your facility is required to have 

flare/vent meters: 

(1) You must maintain the meter recordings for 6 years. 

(i) You must keep these recordings 

on the facility for 2 years and have 

them available for inspection by BSEE 

representatives. 

(ii) After 2 years, you must maintain 

the recordings, allow BSEE representatives to inspect the recordings upon request and provide copies to the Regional Supervisor upon request, but are 

not required to keep them on the facility. 

(iii) These recordings must include 

the begin times, end times, and volumes for all flaring and venting incidents. 

(2) You must maintain flare/vent 

meter calibration and maintenance 

records on the facility for 2 years. 

(e) If your flaring or venting of gas, 

or burning of liquid hydrocarbons, required written or oral approval, you 

must submit documentation to the Regional Supervisor summarizing the location, dates, number of hours, and 

volumes of gas flared, gas vented, and 

liquid hydrocarbons burned under the 

approval. 

§ 250.1164 What are the requirements 

for flaring or venting gas containing H2S? 

(a) You may not vent gas containing 

H2S, except for minor releases during 

maintenance and repair activities that 

do not result in a 15-minute timeweighted average atmosphere concentration of H2S of 20 ppm or higher 

anywhere on the platform. 

(b) You may flare gas containing H2S 

only if you meet the requirements of 

§§250.1160, 250.1161, 250.1163, and the following additional requirements: 


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Safety & Environmental Enforcement, Interior § 250.1167 

(1) For safety or air pollution prevention purposes, the Regional Supervisor 

may further restrict the flaring of gas 

containing H2S. The Regional Supervisor will use information provided in 

the lessee’s H2S Contingency Plan 

(§250.490(f)), Exploration Plan, DPP, 

DOCD submitted to BOEM, and associated documents to determine the need 

for restrictions; and 

(2) If the Regional Supervisor determines that flaring at a facility or 

group of facilities may significantly affect the air quality of an onshore area, 

the Regional Supervisor may require 

you to conduct an air quality modeling 

analysis, under 30 CFR 550.303, to determine the potential effect of facility 

emissions. The Regional Supervisor 

may require monitoring and reporting, 

or may restrict or prohibit flaring, 

under 30 CFR 550.303 and 30 CFR 550.304. 

(c) The Regional Supervisor may require you to submit monthly reports of 

flared and vented gas containing H2S. 

Each report must contain, on a daily 

basis: 

(1) The volume and duration of each 

flaring and venting occurrence; 

(2) H2S concentration in the flared or 

vented gas; and 

(3) The calculated amount of SO2

emitted. 

OTHER REQUIREMENTS

§ 250.1165 What must I do for enhanced recovery operations? 

(a) You must promptly initiate enhanced oil and gas recovery operations 

for all reservoirs where these operations would result in an increase in 

ultimate recovery of oil or gas under 

sound engineering and economic principles. 

(b) Before initiating enhanced recovery operations, you must submit a proposed plan to the BSEE Regional Supervisor and receive approval for pressure maintenance, secondary or tertiary recovery, cycling, and similar recovery operations intended to increase 

the ultimate recovery of oil and gas 

from a reservoir. The proposed plan 

must include, for each project reservoir, a geologic and engineering overview, Form BOEM–0127, and supporting 

data as required in §250.1167, 30 CFR 

550.1167, and any additional information required by the BSEE Regional 

Supervisor. 

(c) You must report to Office of Natural Resources Revenue the volumes of 

oil, gas, or other substances injected, 

produced, or produced for a second 

time under 30 CFR 1210.102. 

§ 250.1166 What additional reporting is 

required for developments in the 

Alaska OCS Region? 

(a) For any development in the Alaska OCS Region, you must submit an 

annual reservoir management report to 

the Regional Supervisor. The report 

must contain information detailing the 

activities performed during the previous year and planned for the upcoming year that will: 

(1) Provide for the prevention of 

waste; 

(2) Provide for the protection of correlative rights; and 

(3) Maximize ultimate recovery of oil 

and gas. 

(b) If your development is jointly regulated by BSEE and the State of Alaska, BSEE and the Alaska Oil and Gas 

Conservation Commission will jointly 

determine appropriate reporting requirements to minimize or eliminate 

duplicate reporting requirements. 

(c) [Reserved] 

§ 250.1167 What information must I 

submit with forms and for approvals? 

You must submit the supporting information listed in the following table 

with the form identified in column 1 

and for the approvals required under 

this subpart identified in columns 2 

through 4: 

WPT BSEE– 

0126 

(2 copies) 

Gas cap production Downhole 

commingling 

Production 

within 500-ft of 

a unit or lease 

line 

(a) Maps: 

(1) Base map with surface, bottomhole, and completion locations with respect to the unit or lease 

line and the orientation of representative seismic lines or cross-sections .................................. ........................ ✔ ✔ ✔ 


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§ 250.1200 30 CFR Ch. II (7–1–13 Edition) 

WPT BSEE– 

0126 

(2 copies) 

Gas cap production Downhole 

commingling 

Production 

within 500-ft of 

a unit or lease 

line 

(2) Structure maps with penetration point and 

subsea depth for each well penetrating the reservoirs, highlighting subject wells; reservoir 

boundaries; and original and current fluid levels ✔ ✔ ✔ ✔ 

(3) Net sand isopach with total net sand penetrated for each well, identified at the penetration 

point ..................................................................... ........................ ✔ ✔ 

(4) Net hydrocarbon isopach with net feet of pay 

for each well, identified at the penetration point ........................ ✔ ✔ 

(b) Seismic data: 

(1) Representative seismic lines, including strike 

and dip lines that confirm the structure; indicate 

polarity ................................................................. ........................ ✔ ✔ ✔ 

(2) Amplitude extraction of seismic horizon, if applicable ................................................................ ........................ ✔ ✔ ✔ 

(c) Logs: 

(1) Well log sections with tops and bottoms of the 

reservoir(s) and proposed or existing perforations ..................................................................... ✔ ✔ ✔ ✔ 

(2) Structural cross-sections showing the subject 

well and nearby wells .......................................... ........................ ✔ ✔ * 

(d) Engineering data: 

(1) Estimated recoverable reserves for each well 

completion in the reservoir; total recoverable reserves for each reservoir; method of calculation; 

reservoir parameters used in volumetric and decline curve analysis ............................................. ........................ † † ✔ 

(2) Well schematics showing current and proposed conditions ................................................. ........................ ✔ ✔ ✔ 

(3) The drive mechanism of each reservoir ........... ........................ ✔ ✔ ✔ 

(4) Pressure data, by date, and whether they are 

estimated or measured ....................................... ........................ ✔ ✔ 

(5) Production data and decline curve analysis indicative of the reservoir performance ................. ........................ ✔ ✔ 

(6) Reservoir simulation with the reservoir parameters used, history matches, and prediction runs 

(include proposed development scenario) .......... ........................ * * * 

(e) General information: 

(1) Detailed economic analysis .............................. ........................ * * 

(2) Reservoir name and whether or not it is competitive as defined under § 250.105 .................... ........................ ✔ ✔ ✔ 

(3) Operator name, lessee name(s), block, lease 

number, royalty rate, and unit number (if applicable) of all relevant leases ................................ ........................ ✔ ✔ ✔ 

(4) Geologic overview of project ............................. ........................ ✔ ✔ ✔ 

(5) Explanation of why the proposed completion 

scenario will maximize ultimate recovery ........... ........................ ✔ ✔ ✔ 

(6) List of all wells in subject reservoirs that have 

ever produced or been used for injection ........... ........................ ✔ ✔ ✔ 

✔ Required. 

† Each Gas Cap Production request and Downhole Commingling request must include the estimated recoverable reserves for 

(1) the case where your proposed production scenario is approved, and (2) the case where your proposed production scenario is 

denied. * Additional items the Regional Supervisor may request. 

Note: All maps must be at a standard scale and show lease and unit lines. The Regional Supervisor may waive submittal of 

some of the required data on a case-by-case basis. 

(f) Depending on the type of approval 

requested, you must submit the appropriate payment of the service fee(s) 

listed in §250.125, according to the instructions in §250.126. 

Subpart L—Oil and Gas Production Measurement, Surface 

Commingling, and Security 

§ 250.1200 Question index table. 

The table in this section lists questions concerning Oil and Gas Production Measurement, Surface Commingling, and Security. 


ehiers on DSK2VPTVN1PROD with CFR
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Safety & Environmental Enforcement, Interior § 250.1201 

Frequently asked questions CFR citation 

1. What are the requirements for measuring liquid hydrocarbons? § 250.1202(a) 

2. What are the requirements for liquid hydrocarbon royalty meters? § 250.1202(b) 

3. What are the requirements for run tickets? § 250.1202(c) 

4. What are the requirements for liquid hydrocarbon royalty meter provings? § 250.1202(d) 

5. What are the requirements for calibrating a master meter used in royalty meter provings? § 250.1202(e) 

6. What are the requirements for calibrating mechanical-displacement provers and tank provers? § 250.1202(f) 

7. What correction factors must a lessee use when proving meters with a mechanical displacement 

prover, tank prover, or master meter? 

§ 250.1202(g) 

8. What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? § 250.1202(h) 

9. Under what circumstances does a liquid hydrocarbon royalty meter need to be taken out of service, 

and what must a lessee do? 

§ 250.1202(i) 

10. How must a lessee correct gross liquid hydrocarbon volumes to standard conditions? § 250.1202(j) 

11. What are the requirements for liquid hydrocarbon allocation meters? § 250.1202(k) 

12. What are the requirements for royalty and inventory tank facilities? § 250.1202(l) 

13. To which meters do BSEE requirements for gas measurement apply? § 250.1203(a) 

14. What are the requirements for measuring gas? § 250.1203(b) 

15. What are the requirements for gas meter calibrations? § 250.1203(c) 

16. What must a lessee do if a gas meter is out of calibration or malfunctioning? § 250.1203(d) 

17. What are the requirements when natural gas from a Federal lease is transferred to a gas plant before royalty determination? § 250.1203(e) 

18. What are the requirements for measuring gas lost or used on a lease? § 250.1203(f) 

19. What are the requirements for the surface commingling of production? § 250.1204(a) 

20. What are the requirements for a periodic well test used for allocation? § 250.1204(b) 

21. What are the requirements for site security? § 250.1205(a) 

22. What are the requirements for using seals? § 250.1205(b) 

§ 250.1201 Definitions. 

Terms not defined in this section 

have the meanings given in the applicable chapter of the API MPMS, which 

is incorporated by reference in §250.198. 

Terms used in Subpart L have the following meaning: 

Allocation meter—a meter used to determine the portion of hydrocarbons 

attributable to one or more platforms, 

leases, units, or wells, in relation to 

the total production from a royalty or 

allocation measurement point. 

API MPMS—the American Petroleum 

Institute’s Manual of Petroleum Measurement Standards, chapters 1, 20, and 

21. 

British Thermal Unit (Btu)—the 

amount of heat needed to raise the 

temperature of one pound of water 

from 59.5 degrees Fahrenheit (59.5 °F) 

to 60.5 degrees Fahrenheit (60.5 °F) at 

standard pressure base (14.73 pounds 

per square inch absolute (psia)). 

Compositional Analysis—separating 

mixtures into identifiable components 

expressed in mole percent. 

Force majeure event—an event beyond 

your control such as war, act of terrorism, crime, or act of nature which 

prevents you from operating the wells 

and meters on your OCS facility. 

Gas lost—gas that is neither sold nor 

used on the lease or unit nor used internally by the producer. 

Gas processing plant—an installation 

that uses any process designed to remove elements or compounds (hydrocarbon and non-hydrocarbon) from gas, 

including absorption, adsorption, or refrigeration. Processing does not include treatment operations, including 

those necessary to put gas into marketable conditions such as natural 

pressure reduction, mechanical separation, heating, cooling, dehydration, 

desulphurization, and compression. The 

changing of pressures or temperatures 

in a reservoir is not processing. 

Gas processing plant statement—a 

monthly statement showing the volume and quality of the inlet or field 

gas stream and the plant products recovered during the period, volume of 

plant fuel, flare and shrinkage, and the 

allocation of these volumes to the 

sources of the inlet stream. 

Gas royalty meter malfunction—an 

error in any component of the gas 

measurement system which exceeds 

contractual tolerances. 

Gas volume statement—a monthly 

statement showing gas measurement 

data, including the volume (Mcf) and 

quality (Btu) of natural gas which 

flowed through a meter. 


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§ 250.1202 30 CFR Ch. II (7–1–13 Edition) 

Inventory tank—a tank in which liquid hydrocarbons are stored prior to 

royalty measurement. The measured 

volumes are used in the allocation 

process. 

Liquid hydrocarbons (free liquids)—hydrocarbons which exist in liquid form 

at standard conditions after passing 

through separating facilities. 

Malfunction factor—a liquid hydrocarbon royalty meter factor that differs from the previous meter factor by 

an amount greater than 0.0025. 

Natural gas—a highly compressible, 

highly expandable mixture of hydrocarbons which occurs naturally in a 

gaseous form and passes a meter in 

vapor phase. 

Operating meter—a royalty or allocation meter that is used for gas or liquid 

hydrocarbon measurement for any period during a calibration cycle. 

Pipeline (retrograde) condensate—liquid hydrocarbons which drop out of the 

separated gas stream at any point in a 

pipeline during transmission to shore. 

Pressure base—the pressure at which 

gas volumes and quality are reported. 

The standard pressure base is 14.73 psia. 

Prove—to determine (as in meter 

proving) the relationship between the 

volume passing through a meter at one 

set of conditions and the indicated volume at those same conditions. 

Royalty meter—a meter approved for 

the purpose of determining the volume 

of gas, oil, or other components removed, saved, or sold from a Federal 

lease. 

Royalty tank—an approved tank in 

which liquid hydrocarbons are measured and upon which royalty volumes 

are based. 

Run ticket—the invoice for liquid hydrocarbons measured at a royalty 

point. 

Sales meter—a meter at which custody 

transfer takes place (not necessarily a 

royalty meter). 

Seal—a device or approved method 

used to prevent tampering with royalty 

measurement components. 

Standard conditions—atmospheric 

pressure of 14.73 pounds per square inch 

absolute (psia) and 60 °F. 

Surface commingling—the surface mixing of production from two or more 

leases and/or unit participating areas 

prior to royalty measurement. 

Temperature base—the temperature at 

which gas and liquid hydrocarbon volumes and quality are reported. The 

standard temperature base is 60 °F. 

Verification/Calibration—testing and 

correcting, if necessary, a measuring 

device to ensure compliance with industry accepted, manufacturer’s recommended, or regulatory required 

standard of accuracy. 

You or your—the lessee or the operator or other lessees’ representative 

engaged in operations in the Outer 

Continental Shelf (OCS). 

§ 250.1202 Liquid hydrocarbon measurement. 

(a) What are the requirements for measuring liquid hydrocarbons? You must: 

(1) Submit a written application to, 

and obtain approval from, the Regional 

Supervisor before commencing liquid 

hydrocarbon production, or making 

any changes to the previously-approved 

measurement and/or allocation procedures. Your application (which may 

also include any relevant gas measurement and surface commingling requests) must be accompanied by payment of the service fee listed in 

§250.125. The service fees are divided 

into two levels based on complexity as 

shown in the following table. 

Application type Actions 

(i) Simple applications, Applications to temporarily reroute production (for a duration not to exceed six months); Production tests prior to pipeline construction; Departures related to meter proving, well testing, 

or sampling frequency. 

(ii) Complex applications, Creation of new facility measurement points (FMPs); Association of leases or units with existing FMPs; Inclusion of production from additional structures; Meter updates which add buyback gas meters or pigging meters; Other applications which request deviations from the approved allocation procedures. 

(2) Use measurement equipment and 

procedures that will accurately measure the liquid hydrocarbons produced from a lease or unit to comply with the 


ehiers on DSK2VPTVN1PROD with CFR
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Safety & Environmental Enforcement, Interior § 250.1202 

following additional API MPMS industry standards or API RP: 

(i) API MPMS, Chapter 4, Section 8 

(incorporated by reference as specified 

in §250.198); 

(ii) API MPMS, Chapter 5, Section 6 

(incorporated by reference as specified 

in §250.198); 

(iii) API MPMS, Chapter 5, Section 8 

(incorporated by reference as specified 

in §250.198); 

(iv) API MPMS, Chapter 11, Section 1 

(incorporated by reference as specified 

in §250.198); 

(v) API MPMS Chapter 12, Section 2, 

Part 3 (incorporated by reference as 

specified in §250.198); 

(vi) API MPMS Chapter 12, Section 2, 

Part 4 (incorporated by reference as 

specified in §250.198); 

(vii) API MPMS, Chapter 21, Section 

2 (incorporated by reference as specified in §250.198); 

(viii) API MPMS, Chapter 21, Addendum to Section 2 (incorporated by reference as specified in §250.198); 

(ix) API RP 86 (incorporated by reference as specified in §250.198); 

(3) Use procedures and correction factors according to the applicable chapters of the API MPMS or RP as incorporated by reference in 30 CFR 250.198, 

including the following additional editions: 

(i) API MPMS, Chapter 4, Section 8 

(incorporated by reference as specified 

in §250.198); 

(ii) API MPMS, Chapter 5, Section 6 

(incorporated by reference as specified 

in §250.198); 

(iii) API MPMS, Chapter 5, Section 8 

(incorporated by reference as specified 

in §250.198); 

(iv) API MPMS Chapter 11, Section 1 

(incorporated by reference as specified 

in §250.198); 

(v) API MPMS Chapter 12, Section 2, 

Part 3 (incorporated by reference as 

specified in §250.198); 

(vi) API MPMS Chapter 12, Section 2, 

Part 4 (incorporated by reference as 

specified in §250.198); 

(vii) API RP 86 (incorporated by reference as specified in §250.198); when 

obtaining net standard volume and associated measurement parameters; and 

(4) When requested by the Regional 

Supervisor, provide the pipeline (retrograde) condensate volumes as allocated 

to the individual leases or units. 

(b) What are the requirements for liquid 

hydrocarbon royalty meters? You must: 

(1) Ensure that the royalty meter facilities include the following approved 

components (or other BSEE-approved 

components) which must be compatible 

with their connected systems: 

(i) A meter equipped with a nonreset 

totalizer; 

(ii) A calibrated mechanical displacement (pipe) prover, master meter, or 

tank prover; 

(iii) A proportional-to-flow sampling 

device pulsed by the meter output; 

(iv) A temperature measurement or 

temperature compensation device; and 

(v) A sediment and water monitor 

with a probe located upstream of the 

divert valve. 

(2) Ensure that the royalty meter facilities accomplish the following: 

(i) Prevent flow reversal through the 

meter; 

(ii) Protect meters subjected to pressure pulsations or surges; 

(iii) Prevent the meter from being 

subjected to shock pressures greater 

than the maximum working pressure; 

and 

(iv) Prevent meter bypassing. 

(3) Maintain royalty meter facilities 

to ensure the following: 

(i) Meters operate within the gravity 

range specified by the manufacturer; 

(ii) Meters operate within the manufacturer’s specifications for maximum 

and minimum flow rate for linear accuracy; and 

(iii) Meters are reproven when 

changes in metering conditions affect 

the meters’ performance such as 

changes in pressure, temperature, density (water content), viscosity, pressure, and flow rate. 

(4) Ensure that sampling devices conform to the following: 

(i) The sampling point is in the 

flowstream immediately upstream or 

downstream of the meter or divert 

valve in accordance with the API 

MPMS (as incorporated by reference in 

§250.198); 

(ii) The sample container is vaportight and includes a power mixing device to allow complete mixing of the 

sample before removal from the container; and 


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§ 250.1202 30 CFR Ch. II (7–1–13 Edition) 

(iii) The sample probe is in the center 

half of the pipe diameter in a vertical 

run and is located at least three pipe 

diameters downstream of any pipe fitting within a region of turbulent flow. 

The sample probe can be located in a 

horizontal pipe if adequate stream conditioning such as power mixers or static mixers are installed upstream of the 

probe according to the manufacturer’s 

instructions. 

(c) What are the requirements for run 

tickets? You must: 

(1) For royalty meters, ensure that 

the run tickets clearly identify all observed data, all correction factors not 

included in the meter factor, and the 

net standard volume. 

(2) For royalty tanks, ensure that the 

run tickets clearly identify all observed data, all applicable correction 

factors, on/off seal numbers, and the 

net standard volume. 

(3) Pull a run ticket at the beginning 

of the month and immediately after establishing the monthly meter factor or 

a malfunction meter factor. 

(4) Send all run tickets for royalty 

meters and tanks to the Regional Supervisor within 15 days after the end of 

the month; 

(d) What are the requirements for liquid 

hydrocarbon royalty meter provings? You 

must: 

(1) Permit BSEE representatives to 

witness provings; 

(2) Ensure that the integrity of the 

prover calibration is traceable to test 

measures certified by the National Institute of Standards and Technology; 

(3) Prove each operating royalty 

meter to determine the meter factor 

monthly, but the time between meter 

factor determinations must not exceed 

42 days. When a force majeure event 

precludes the required monthly meter 

proving, meters must be proved within 

15 days after being returned to service. 

The meters must be proved monthly 

thereafter, but the time between meter 

factor determinations must not exceed 

42 days; 

(4) Obtain approval from the Regional Supervisor before proving on a 

schedule other than monthly; and 

(5) Submit copies of all meter proving reports for royalty meters to the 

Regional Supervisor monthly within 15 

days after the end of the month. 

(e) What are the requirements for calibrating a master meter used in royalty 

meter provings? You must: 

(1) Calibrate the master meter to obtain a master meter factor before using 

it to determine operating meter factors; 

(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as 

the liquid hydrocarbons that flow 

through the operating meter to calibrate the master meter; 

(3) Calibrate the master meter 

monthly, but the time between calibrations must not exceed 42 days; 

(4) Calibrate the master meter by recording runs until the results of two 

consecutive runs (if a tank prover is 

used) or five out of six consecutive runs 

(if a mechanical-displacement prover is 

used) produce meter factor differences 

of no greater than 0.0002. Lessees must 

use the average of the two (or the five) 

runs that produced acceptable results 

to compute the master meter factor; 

(5) Install the master meter upstream 

of any back-pressure or reverse flow 

check valves associated with the operating meter. However, the master 

meter may be installed either upstream or downstream of the operating 

meter; and 

(6) Keep a copy of the master meter 

calibration report at your field location for 2 years. 

(f) What are the requirements for calibrating mechanical-displacement provers 

and tank provers? You must: 

(1) Calibrate mechanical-displacement provers and tank provers at least 

once every 5 years according to the 

API MPMS as incorporated by reference in 30 CFR 250.198, including the 

following additional editions: 

(i) API MPMS, Chapter 4, Section 8 

(incorporated by reference as specified 

in §250.198); 

(ii) API MPMS Chapter 12, Section 2, 

Part 4 (incorporated by reference as 

specified in §250.198); 

(2) Submit a copy of each calibration 

report to the Regional Supervisor within 15 days after the calibration. 

(g) What correction factors must I use 

when proving meters with a mechanicaldisplacement prover, tank prover, or master meter? Calculate the following correction factors using the API MPMS as 


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Safety & Environmental Enforcement, Interior § 250.1202 

referenced in 30 CFR 250.198, including 

the following additional editions: 

(1) API MPMS, Chapter 4, Section 8 

(incorporated by reference as specified 

in §250.198); 

(2) API MPMS Chapter 11, Section 1 

(incorporated by reference as specified 

in §250.198); 

(3) API MPMS Chapter 12, Section 2, 

Part 3 (incorporated by reference as 

specified in §250.198); 

(4) API MPMS Chapter 12, Section 2, 

Part 4 (incorporated by reference as 

specified in §250.198); 

(h) What are the requirements for establishing and applying operating meter factors for liquid hydrocarbons? (1) If you 

use a mechanical-displacement prover, 

you must record proof runs until five 

out of six consecutive runs produce a 

difference between individual runs of 

no greater than .05 percent. You must 

use the average of the five accepted 

runs to compute the meter factor. 

(2) If you use a master meter, you 

must record proof runs until three consecutive runs produce a total meter 

factor difference of no greater than 

0.0005. The flow rate through the meters during the proving must be within 

10 percent of the rate at which the line 

meter will operate. The final meter 

factor is determined by averaging the 

meter factors of the three runs; 

(3) If you use a tank prover, you must 

record proof runs until two consecutive 

runs produce a meter factor difference 

of no greater than .0005. The final 

meter factor is determined by averaging the meter factors of the two 

runs; and 

(4) You must apply operating meter 

factors forward starting with the date 

of the proving. 

(i) Under what circumstances does a liquid hydrocarbon royalty meter need to be 

taken out of service, and what must I do? 

(1) If the difference between the meter 

factor and the previous factor exceeds 

0.0025 it is a malfunction factor, and 

you must: 

(i) Remove the meter from service 

and inspect it for damage or wear; 

(ii) Adjust or repair the meter, and 

reprove it; 

(iii) Apply the average of the malfunction factor and the previous factor 

to the production measured through 

the meter between the date of the previous factor and the date of the malfunction factor; and 

(iv) Indicate that a meter malfunction occurred and show all appropriate 

remarks regarding subsequent repairs 

or adjustments on the proving report. 

(2) If a meter fails to register production, you must: 

(i) Remove the meter from service, 

repair and reprove it; 

(ii) Apply the previous meter factor 

to the production run between the date 

of that factor and the date of the failure; and 

(iii) Estimate and report unregistered 

production on the run ticket. 

(3) If the results of a royalty meter 

proving exceed the run tolerance criteria and all measures excluding the 

adjustment or repair of the meter cannot bring results within tolerance, you 

must: 

(i) Establish a factor using proving 

results made before any adjustment or 

repair of the meter; and 

(ii) Treat the established factor like 

a malfunction factor (see paragraph 

(i)(1) of this section). 

(j) How must I correct gross liquid hydrocarbon volumes to standard conditions? To correct gross liquid hydrocarbon volumes to standard conditions, 

you must: 

(1) Include Cpl factors in the meter 

factor calculation or list and apply 

them on the appropriate run ticket. 

(2) List Ctl factors on the appropriate 

run ticket when the meter is not automatically temperature compensated. 

(k) What are the requirements for liquid 

hydrocarbon allocation meters? For liquid hydrocarbon allocation meters you 

must: 

(1) Take samples continuously proportional to flow or daily (use the procedure in the applicable chapter of the 

API MPMS as incorporated by reference in §250.198; 

(2) For turbine meters, take the sample proportional to the flow only; 

(3) Prove operating allocation meters 

monthly if they measure 50 or more 

barrels per day per meter the previous 

month. When a force majeure event 

precludes the required monthly meter 

proving, meters must be proved within 

15 days after being returned to service. 

The meters must be proved monthly 

thereafter; or 


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§ 250.1203 30 CFR Ch. II (7–1–13 Edition) 

(4) Prove operating allocation meters 

quarterly if they measure less than 50 

barrels per day per meter the previous 

month. When a force majeure event 

precludes the required quarterly meter 

proving, meters must be proved within 

15 days after being returned to service. 

The meters must be proved quarterly 

thereafter; 

(5) Keep a copy of the proving reports 

at the field location for 2 years; 

(6) Adjust and reprove the meter if 

the meter factor differs from the previous meter factor by more than 2 percent and less than 7 percent; 

(7) For turbine meters, remove from 

service, inspect and reprove the meter 

if the factor differs from the previous 

meter factor by more than 2 percent 

and less than 7 percent; 

(8) Repair and reprove, or replace and 

prove the meter if the meter factor differs from the previous meter factor by 

7 percent or more; and 

(9) Permit BSEE representatives to 

witness provings. 

(l) What are the requirements for royalty and inventory tank facilities? You 

must: 

(1) Equip each royalty and inventory 

tank with a vapor-tight thief hatch, a 

vent-line valve, and a fill line designed 

to minimize free fall and splashing; 

(2) For royalty tanks, submit a complete set of calibration charts (tank tables) to the Regional Supervisor before 

using the tanks for royalty measurement; 

(3) For inventory tanks, retain the 

calibration charts for as long as the 

tanks are in use and submit them to 

the Regional Supervisor upon request; 

and 

(4) Obtain the volume and other 

measurement parameters by using corrections factors and procedures in the 

API MPMS as incorporated by reference in 30 CFR 250.198, including: API 

MPMS Chapter 11, Section 1 (incorporated by reference as specified in 

§250.198). 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 18921, Mar. 29, 2012] 

§ 250.1203 Gas measurement. 

(a) To which meters do BSEE requirements for gas measurement apply? BSEE 

requirements for gas measurements 

apply to all OCS gas royalty and allocation meters. 

(b) What are the requirements for measuring gas? You must: 

(1) Submit a written application to, 

and obtain approval from, the Regional 

Supervisor before commencing gas production, or making any changes to the 

previously-approved measurement and/ 

or allocation procedures. Your application (which may also include any relevant liquid hydrocarbon measurement 

and surface commingling requests) 

must be accompanied by payment of 

the service fee listed in §250.125. The 

service fees are divided into two levels 

based on complexity, see table in 

§250.1202(a)(1). 

(2) Design, install, use, maintain, and 

test measurement equipment and procedures to ensure accurate and 

verifiable measurement. You must follow the recommendations in API 

MPMS or RP and AGA as incorporated 

by reference in 30 CFR 250.198, including the following additional editions: 

(i) API RP 86 (incorporated by reference as specified in §250.198); 

(ii) AGA Report No. 7 (incorporated 

by reference as specified in §250.198); 

(iii) AGA Report No. 9 (incorporated 

by reference as specified in §250.198); 

(iv) AGA Report No. 10 (incorporated 

by reference as specified in §250.198); 

(3) Ensure that the measurement 

components demonstrate consistent 

levels of accuracy throughout the system. 

(4) Equip the meter with a chart or 

electronic data recorder. If an electronic data recorder is used, you must 

follow the recommendations in API 

MPMS. 

(5) Take proportional-to-flow or spot 

samples upstream or downstream of 

the meter at least once every 6 months. 

(6) When requested by the Regional 

Supervisor, provide available information on the gas quality. 

(7) Ensure that standard conditions 

for reporting gross heating value (Btu) 

are at a base temperature of 60 °F and 

at a base pressure of 14.73 psia and reflect the same degree of water saturation as in the gas volume. 

(8) When requested by the Regional 

Supervisor, submit copies of gas volume statements for each requested gas 

meter. Show whether gas volumes and 


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gross Btu heating values are reported 

at saturated or unsaturated conditions; 

and 

(9) When requested by the Regional 

Supervisor, provide volume and quality 

statements on dispositions other than 

those on the gas volume statement. 

(c) What are the requirements for gas 

meter calibrations? You must: 

(1) Verify/calibrate operating meters 

monthly, but do not exceed 42 days between verifications/calibrations. When 

a force majeure event precludes the required monthly meter verification/calibration, meters must be verified/calibrated within 15 days after being returned to service. The meters must be 

verified/calibrated monthly thereafter, 

but do not exceed 42 days between 

meter verifications/calibrations; 

(2) Calibrate each meter by using the 

manufacturer’s specifications; 

(3) Conduct calibrations as close as 

possible to the average hourly rate of 

flow since the last calibration; 

(4) Retain calibration reports at the 

field location for 2 years, and send the 

reports to the Regional Supervisor 

upon request; and 

(5) Permit BSEE representatives to 

witness calibrations. 

(d) What must I do if a gas meter is out 

of calibration or malfunctioning? If a gas 

meter is out of calibration or malfunctioning, you must: 

(1) If the readings are greater than 

the contractual tolerances, adjust the 

meter to function properly or remove 

it from service and replace it. 

(2) Correct the volumes to the last 

acceptable calibration as follows: 

(i) If the duration of the error can be 

determined, calculate the volume adjustment for that period. 

(ii) If the duration of the error cannot be determined, apply the volume 

adjustment to one-half of the time 

elapsed since the last calibration or 21 

days, whichever is less. 

(e) What are the requirements when 

natural gas from a Federal lease on the 

OCS is transferred to a gas plant before 

royalty determination? If natural gas 

from a Federal lease on the OCS is 

transferred to a gas plant before royalty determination: 

(1) You must provide the following to 

the Regional Supervisor upon request: 

(i) A copy of the monthly gas processing plant allocation statement; and 

(ii) Gross heating values of the inlet 

and residue streams when not reported 

on the gas plant statement. 

(2) You must permit BSEE to inspect 

the measurement and sampling equipment of natural gas processing plants 

that process Federal production. 

(f) What are the requirements for measuring gas lost or used on a lease? (1) You 

must either measure or estimate the 

volume of gas lost or used on a lease. 

(2) If you measure the volume, document the measurement equipment used 

and include the volume measured. 

(3) If you estimate the volume, document the estimating method, the data 

used, and the volumes estimated. 

(4) You must keep the documentation, including the volume data, easily 

obtainable for inspection at the field 

location for at least 2 years, and must 

retain the documentation at a location 

of your choosing for at least 7 years 

after the documentation is generated, 

subject to all other document retention 

and production requirements in 30 

U.S.C. 1713 and 30 CFR part 1212. 

(5) Upon the request of the Regional 

Supervisor, you must provide copies of 

the records. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 18922, Mar. 29, 2012] 

§ 250.1204 Surface commingling. 

(a) What are the requirements for the 

surface commingling of production? You 

must: 

(1) Submit a written application to, 

and obtain approval from, the Regional 

Supervisor before commencing the 

commingling of production or making 

any changes to the previously approved 

commingling procedures. Your application (which may also include any relevant liquid hydrocarbon and gas 

measurement requests) must be accompanied by payment of the service fee 

listed in §250.125. The service fees are 

divided into two levels based on complexity, see table in §250.1202(a)(1). 

(2) Upon the request of the Regional 

Supervisor, lessees who deliver State 

lease production into a Federal commingling system must provide volumetric or fractional analysis data on 

the State lease production through the 

designated system operator. 


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§ 250.1205 30 CFR Ch. II (7–1–13 Edition) 

(b) What are the requirements for a 

periodic well test used for allocation? You 

must: 

(1) Conduct a well test at least once 

every 60 days unless the Regional Supervisor approves a different frequency. When a force majeure event 

precludes the required well test within 

the prescribed 60 day period (or other 

frequency approved by the Regional 

Supervisor), wells must be tested within 15 days after being returned to production. Thereafter, well tests must be 

conducted at least once every 60 days 

(or other frequency approved by the 

Regional Supervisor); 

(2) Follow the well test procedures in 

30 CFR part 250, subpart K; and 

(3) Retain the well test data at the 

field location for 2 years. 

§ 250.1205 Site security. 

(a) What are the requirements for site 

security? You must: 

(1) Protect Federal production 

against production loss or theft; 

(2) Post a sign at each royalty or inventory tank which is used in the royalty determination process. The sign 

must contain the name of the facility 

operator, the size of the tank, and the 

tank number; 

(3) Not bypass BSEE-approved liquid 

hydrocarbon royalty meters and tanks; 

and 

(4) Report the following to the Regional Supervisor as soon as possible, 

but no later than the next business day 

after discovery: 

(i) Theft or mishandling of production; 

(ii) Tampering or bypassing any component of the royalty measurement facility; and 

(iii) Falsifying production measurements. 

(b) What are the requirements for using 

seals? You must: 

(1) Seal the following components of 

liquid hydrocarbon royalty meter installations to ensure that tampering 

cannot occur without destroying the 

seal: 

(i) Meter component connections 

from the base of the meter up to and 

including the register; 

(ii) Sampling systems including 

packing device, fittings, sight glass, 

and container lid; 

(iii) Temperature and gravity compensation device components; 

(iv) All valves on lines leaving a royalty or inventory storage tank, including load-out line valves, drain-line 

valves, and connection-line valves between royalty and non-royalty tanks; 

and 

(v) Any additional components required by the Regional Supervisor. 

(2) Seal all bypass valves of gas royalty and allocation meters. 

(3) Number and track the seals and 

keep the records at the field location 

for at least 2 years; and 

(4) Make the records of seals available for BSEE inspection. 

Subpart M—Unitization 

§ 250.1300 What is the purpose of this 

subpart? 

This subpart explains how Outer Continental Shelf (OCS) leases are unitized. If you are an OCS lessee, use the 

regulations in this subpart for both 

competitive reservoir and unitization 

situations. The purpose of joint development and unitization is to: 

(a) Conserve natural resources; 

(b) Prevent waste; and/or 

(c) Protect correlative rights, including Federal royalty interests. 

§ 250.1301 What are the requirements 

for unitization? 

(a) Voluntary unitization. You and 

other OCS lessees may ask the Regional Supervisor to approve a request 

for voluntary unitization. The Regional Supervisor may approve the request for voluntary unitization if unitized operations: 

(1) Promote and expedite exploration 

and development; or 

(2) Prevent waste, conserve natural 

resources, or protect correlative rights, 

including Federal royalty interests, of 

a reasonably delineated and productive 

reservoir. 

(b) Compulsory unitization. The Regional Supervisor may require you and 

other lessees to unitize operations of a 

reasonably delineated and productive 

reservoir if unitized operations are necessary to: 

(1) Prevent waste; 

(2) Conserve natural resources; or 


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Safety & Environmental Enforcement, Interior § 250.1302 

(3) Protect correlative rights, including Federal royalty interests. 

(c) Unit area. The area that a unit includes is the minimum number of 

leases that will allow the lessees to 

minimize the number of platforms, facility installations, and wells necessary for efficient exploration, development, and production of mineral deposits, oil and gas reservoirs, or potential hydrocarbon accumulations common to two or more leases. A unit may 

include whole leases or portions of 

leases. 

(d) Unit agreement. You, the other lessees, and the unit operator must enter 

into a unit agreement. The unit agreement must: allocate benefits to unitized leases, designate a unit operator, 

and specify the effective date of the 

unit agreement. The unit agreement 

must terminate when: the unit no 

longer produces unitized substances, 

and the unit operator no longer conducts drilling or well-workover operations (§250.180) under the unit agreement, unless the Regional Supervisor 

orders or approves a suspension of production under §250.170. 

(e) Unit operating agreement. The unit 

operator and the owners of working interests in the unitized leases must 

enter into a unit operating agreement. 

The unit operating agreement must describe how all the unit participants 

will apportion all costs and liabilities 

incurred maintaining or conducting operations. When a unit involves one or 

more net-profit-share leases, the unit 

operating agreement must describe 

how to attribute costs and credits to 

the net-profit-share lease(s), and this 

part of the agreement must be approved by the Regional Supervisor. 

Otherwise, you must provide a copy of 

the unit operating agreement to the 

Regional Supervisor, but the Regional 

Supervisor does not need to approve 

the unit operating agreement. 

(f) Extension of a lease covered by unit 

operations. If your unit agreement expires or terminates, or the unit area 

adjusts so that no part of your lease remains within the unit boundaries, your 

lease expires unless: 

(1) Its initial term has not expired; 

(2) You conduct drilling, production, 

or well-reworking operations on your 

lease consistent with applicable regulations; or 

(3) BSEE orders or approves a suspension of production or operations for 

your lease. 

(g) Unit operations. If your lease, or 

any part of your lease, is subject to a 

unit agreement, the entire lease continues for the term provided in the 

lease, and as long thereafter as any 

portion of your lease remains part of 

the unit area, and as long as operations 

continue the unit in effect. 

(1) If you drill, produce or perform 

well-workover operations on a lease 

within a unit, each lease, or part of a 

lease, in the unit will remain active in 

accordance with the unit agreement. 

Following a discovery, if your unit 

ceases drilling activities for a reasonable time period between the delineation of one or more reservoirs and the 

initiation of actual development drilling or production operations and that 

time period would extend beyond your 

lease’s primary term or any extension 

under §250.180, the unit operator must 

request and obtain BSEE approval of a 

suspension of production under §250.170 

in order to keep the unit from terminating. 

(2) When a lease in a unit agreement 

is beyond the primary term and the 

lease or unit is not producing, the lease 

will expire unless: 

(i) You conduct a continuous drilling 

or well reworking program designed to 

develop or restore the lease or unit production; or 

(ii) BSEE orders or approves a suspension of operations under §250.170. 

§ 250.1302 What if I have a competitive 

reservoir on a lease? 

(a) The Regional Supervisor may require you to conduct development and 

production operations in a competitive 

reservoir under either a joint Development and Production Plan, submitted 

to BOEM or a unitization agreement. A 

competitive reservoir has one or more 

producing or producible well completions on each of two or more leases, or 

portions of leases, with different lease 

operating interests. For purposes of 

this paragraph, a producible well completion is a well which is capable of 

production and which is shut in at the 


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§ 250.1303 30 CFR Ch. II (7–1–13 Edition) 

well head or at the surface but not necessarily connected to production facilities and from which the operator plans 

future production. 

(b) You may request that the Regional Supervisor make a preliminary 

determination whether a reservoir is 

competitive. When you receive the preliminary determination, you have 30 

days (or longer if the Regional Supervisor allows additional time) to concur 

or to submit an objection with supporting evidence if you do not concur. 

The Regional Supervisor will make a 

final determination and notify you and 

the other lessees. 

(c) If you conduct drilling or production operations in a reservoir determined competitive by the Regional Supervisor, you and the other affected 

lessees must submit for approval a 

joint plan of operations. You must submit the joint plan within 90 days after 

the Regional Supervisor makes a final 

determination that the reservoir is 

competitive. The joint plan must provide for the development and/or production of the reservoir. You may submit supplemental plans for the Regional Supervisor’s approval. 

(d) If you and the other affected lessees cannot reach an agreement on a 

joint Development and Production 

Plan, submitted to BOEM within the 

approved period of time, each lessee 

must submit a separate plan to the Regional Supervisor. The Regional Supervisor will hold a hearing to resolve differences in the separate plans. If the 

differences in the separate plans are 

not resolved at the hearing and the Regional Supervisor determines that 

unitization is necessary under 

§250.1301(b), BSEE will initiate unitization under §250.1304. 

§ 250.1303 How do I apply for voluntary unitization? 

(a) You must file a request for a voluntary unit with the Regional Supervisor. Your request must include: 

(1) A draft of the proposed unit agreement; 

(2) A proposed initial plan of operation; 

(3) Supporting geological, geophysical, and engineering data; and 

(4) Other information that may be 

necessary to show that the unitization 

proposal meets the criteria of §250.1300. 

(b) The unit agreement must comply 

with the requirements of this part. 

BSEE will maintain and provide a 

model unit agreement for you to follow. If BSEE revises the model, BSEE 

will publish the revised model in the 

FEDERAL REGISTER. If you vary your 

unit agreement from the model agreement, you must obtain the approval of 

the Regional Supervisor. 

(c) After the Regional Supervisor accepts your unitization proposal, you, 

the other lessees, and the unit operator 

must sign and file copies of the unit 

agreement, the unit operating agreement, and the initial plan of operation 

with the Regional Supervisor for approval. 

(d) You must pay the service fee listed in §250.125 of this part with your request for a voluntary unitization proposal or the expansion of a previously 

approved voluntary unit to include additional acreage. Additionally, you 

must pay the service fee listed in 

§250.125 with your request for unitization revision. 

§ 250.1304 How will BSEE require unitization? 

(a) If the Regional Supervisor determines that unitization of operations 

within a proposed unit area is necessary to prevent waste, conserve natural resources of the OCS, or protect 

correlative rights, including Federal 

royalty interests, the Regional Supervisor may require unitization. 

(b) If you ask BSEE to require unitization, you must file a request with 

the Regional Supervisor. You must include a proposed unit agreement as described in §§250.1301(d) and 250.1303(b); a 

proposed unit operating agreement; a 

proposed initial plan of operation; supporting geological, geophysical, and 

engineering data; and any other information that may be necessary to show 

that unitization meets the criteria of 

§250.1300. The proposed unit agreement 

must include a counterpart executed 

by each lessee seeking compulsory 

unitization. Lessees who seek compulsory unitization must simultaneously 

serve on the nonconsenting lessees copies of: 


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Safety & Environmental Enforcement, Interior § 250.1402 

(1) The request; 

(2) The proposed unit agreement with 

executed counterparts; 

(3) The proposed unit operating 

agreement; and 

(4) The proposed initial plan of operation. 

(c) If the Regional Supervisor initiates compulsory unitization, BSEE will 

serve all lessees of the proposed unit 

area with a proposed unitization plan 

and a statement of reasons for the proposed unitization. 

(d) The Regional Supervisor will not 

require unitization until BSEE provides all lessees of the proposed unit 

area written notice and an opportunity 

for a hearing. If you want BSEE to 

hold a hearing, you must request it 

within 30 days after you receive written notice from the Regional Supervisor or after you are served with a request for compulsory unitization from 

another lessee. 

(e) BSEE will not hold a hearing 

under this paragraph until at least 30 

days after BSEE provides written notice of the hearing date to all parties 

owning interests that would be made 

subject to the unit agreement. The Regional Supervisor must give all lessees 

of the proposed unit area an opportunity to submit views orally and in 

writing and to question both those 

seeking and those opposing compulsory 

unitization. Adjudicatory procedures 

are not required. The Regional Supervisor will make a decision based upon a 

record of the hearing, including any 

written information made a part of the 

record. The Regional Supervisor will 

arrange for a court reporter to make a 

verbatim transcript. The party seeking 

compulsory unitization must pay for 

the court reporter and pay for and provide to the Regional Supervisor within 

10 days after the hearing three copies 

of the verbatim transcript. 

(f) The Regional Supervisor will issue 

an order that requires or rejects compulsory unitization. That order must 

include a statement of reasons for the 

action taken and identify those parts 

of the record which form the basis of 

the decision. Any adversely affected 

party may appeal the final order of the 

Regional Supervisor under 30 CFR part 

290. 

Subpart N—Outer Continental 

Shelf Civil Penalties 

OUTER CONTINENTAL SHELF LANDS ACT

CIVIL PENALTIES

§ 250.1400 How does BSEE begin the 

civil penalty process? 

This subpart explains BSEEs civil 

penalty procedures whenever a lessee, 

operator or other person engaged in oil, 

gas, sulphur or other minerals operations in the OCS has a violation. 

Whenever BSEE determines, on the 

basis of available evidence, that a violation occurred and a civil penalty review is appropriate, it will prepare a 

case file. BSEE will appoint a Reviewing Officer. 

§ 250.1401 Index table. 

The following table is an index of the 

sections in this subpart: 

Definitions. § 250.1402 

What is the maximum civil 

penalty? 

§ 250.1403 

Which violations will BSEE 

review for potential civil 

penalties? 

§ 250.1404 

When is a case file developed? § 250.1405 

When will BSEE notify me 

and provide penalty information? 

§ 250.1406 

How do I respond to the letter of notification? § 250.1407 

When will I be notified of the 

Reviewing Officer’s decision? 

§ 250.1408 

What are my appeal rights? § 250.1409 

§ 250.1402 Definitions. 

Terms used in this subpart have the 

following meaning: 

Case file means a BSEE document file 

containing information and the record 

of evidence related to the alleged violation. 

Civil penalty means a fine. It is a 

BSEE regulatory enforcement tool 

used in addition to Notices of Incidents 

of Noncompliance and directed suspensions of production or other operations. 

Reviewing Officer means a BSEE employee assigned to review case files and 

assess civil penalties. 


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§ 250.1403 30 CFR Ch. II (7–1–13 Edition) 

Violation means failure to comply 

with the Outer Continental Shelf 

Lands Act (OCSLA) or any other applicable laws, with any regulations issued 

under the OCSLA, or with the terms or 

provisions of leases, licenses, permits, 

rights-of-way, or other approvals 

issued under the OCSLA. 

Violator means a person responsible 

for a violation. 

§ 250.1403 What is the maximum civil 

penalty? 

The maximum civil penalty is $40,000 

per day per violation. 

§ 250.1404 Which violations will BSEE 

review for potential civil penalties? 

BSEE will review each of the following violations for potential civil 

penalties: 

(a) Violations that you do not correct 

within the period BSEE grants; 

(b) Violations that BSEE determines 

may constitute, or constituted, a 

threat of serious, irreparable, or immediate harm or damage to life (including 

fish and other aquatic life), property, 

any mineral deposit, or the marine, 

coastal, or human environment; or 

(c) Violations that cause serious, irreparable, or immediate harm or damage to life (including fish and other 

aquatic life), property, any mineral deposit, or the marine, coastal, or human 

environment. 

(d) Violations of the oil spill financial responsibility requirements at 30 

CFR part 553. 

§ 250.1405 When is a case file developed? 

BSEE will develop a case file during 

its investigation of the violation, and 

forward it to a Reviewing Officer if any 

of the conditions in §250.1404 exist. The 

Reviewing Officer will review the case 

file and determine if a civil penalty is 

appropriate. The Reviewing Officer 

may administer oaths and issue subpoenas requiring witnesses to attend 

meetings, submit depositions, or 

produce evidence. 

§ 250.1406 When will BSEE notify me 

and provide penalty information? 

If the Reviewing Officer determines 

that a civil penalty should be assessed, 

the Reviewing Officer will send the violator a letter of notification. The letter 

of notification will include: 

(a) The amount of the proposed civil 

penalty; 

(b) Information on the violation(s); 

and 

(c) Instruction on how to obtain a 

copy of the case file, schedule a meeting, submit information, or pay the 

penalty. 

§ 250.1407 How do I respond to the letter of notification? 

You have 30 calendar days after you 

receive the Reviewing Officer’s letter 

to either: 

(a) Request, in writing, a meeting 

with the Reviewing Officer; 

(b) Submit additional information; or 

(c) Pay the proposed civil penalty. 

§ 250.1408 When will I be notified of 

the Reviewing Officer’s decision? 

At the end of the 30 calendar days or 

after the meeting and submittal of additional information, the Reviewing 

Officer will review the case file, including all information you submitted, and 

send you a decision. The decision will 

include the amount of any final civil 

penalty, the basis for the civil penalty, 

and instructions for paying or appealing the civil penalty. 

§ 250.1409 What are my appeal rights? 

(a) When you receive the Reviewing 

Officer’s final decision, you have 60 

days to either pay the penalty or file 

an appeal in accordance with 30 CFR 

part 290, subpart A. 

(b) If you file an appeal, you must either: 

(1) Submit a surety bond in the 

amount of the penalty to the appropriate Leasing Office in the Region 

where the penalty was assessed, following instructions that the Reviewing 

Officer will include in the final decision; or 

(2) Notify the appropriate Leasing Office, in the Region where the penalty 

was assessed, that you want your leasespecific/area-wide bond on file to be 

used as the bond for the penalty 

amount. 

(c) If you choose the alternative in 

paragraph (b)(2) of this section, the 

BOEM Regional Director may require 


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Safety & Environmental Enforcement, Interior § 250.1454 

additional security (i.e., security in excess of your existing bond) to ensure 

sufficient coverage during an appeal. In 

that event, the Regional Director will 

require you to post the supplemental 

bond with the regional office in the 

same manner as under 30 CFR 556.53(d) 

through (f). If the Regional Director 

determines the appeal should be covered by a lease-specific abandonment 

account then you must establish an account that meets the requirements of 

30 CFR part 556.56. 

(d) If you do not either pay the penalty or file a timely appeal, BSEE will 

take one or more of the following actions: 

(1) We will collect the amount you 

were assessed, plus interest, late payment charges, and other fees as provided by law, from the date you received the Reviewing Officer’s final decision until the date we receive payment; 

(2) We may initiate additional enforcement, including, if appropriate, 

cancellation of the lease, right-of-way, 

license, permit, or approval, or the forfeiture of a bond under this part; or 

(3) We may bar you from doing further business with the Federal Government according to Executive Orders 

12549 and 12689, and section 2455 of the 

Federal Acquisition Streamlining Act 

of 1994, 31 U.S.C. 6101. The Department 

of the Interior’s regulations implementing these authorities are found at 

43 CFR part 12, subpart D. 

FEDERAL OIL AND GAS ROYALTY MANAGEMENT ACT CIVIL PENALTIES DEFINITIONS

§ 250.1450 What definitions apply to 

this subpart? 

The terms used in this subpart have 

the same meaning as in 30 U.S.C. 1702. 

PENALTIES AFTER A PERIOD TO CORRECT

§ 250.1451 What may BSEE do if I violate a statute, regulation, order, or 

lease term relating to a Federal oil 

and gas lease? 

(a) If we believe that you have not 

followed any requirement of a statute, 

regulation, order, or lease term for any 

Federal oil or gas lease, we may send 

you a Notice of Noncompliance informing you what the violation is and what 

you need to do to correct it to avoid 

civil penalties under 30 U.S.C. 1719(a) 

and (b). 

(b) We will serve the Notice of Noncompliance by registered mail or personal service using the most current 

address on file as maintained by the 

BOEM Leasing Office in your respective Region. 

§ 250.1452 What if I correct the violation? 

The matter will be closed if you correct all of the violations identified in 

the Notice of Noncompliance within 20 

days after you receive the Notice (or 

within a longer time period specified in 

the Notice). 

§ 250.1453 What if I do not correct the 

violation? 

(a) We may send you a Notice of Civil 

Penalty if you do not correct all of the 

violations identified in the Notice of 

Noncompliance within 20 days after 

you receive the Notice of Noncompliance (or within a longer time period 

specified in that Notice). The Notice of 

Civil Penalty will tell you how much 

penalty you must pay. The penalty 

may be up to $500 per day, beginning 

with the date of the Notice of Noncompliance, for each violation identified in the Notice of Noncompliance for 

as long as you do not correct the violations. 

(b) If you do not correct all of the 

violations identified in the Notice of 

Noncompliance within 40 days after 

you receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified in 

that Notice), we may increase the penalty to up to $5,000 per day, beginning 

with the date of the Notice of Noncompliance, for each violation for as 

long as you do not correct the violations. 

§ 250.1454 How may I request a hearing on the record on a Notice of 

Noncompliance? 

You may request a hearing on the 

record on a Notice of Noncompliance 

by filing a request within 30 days of the 

date you received the Notice of Noncompliance with the Hearings Division 

(Departmental), Office of Hearings and 


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§ 250.1455 30 CFR Ch. II (7–1–13 Edition) 

Appeals, U.S. Department of the Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may do this regardless of whether you correct the 

violations identified in the Notice of 

Noncompliance. 

§ 250.1455 Does my request for a hearing on the record affect the penalties? 

(a) If you do not correct the violations identified in the Notice of Noncompliance, the penalties will continue 

to accrue even if you request a hearing 

on the record. 

(b) You may petition the Hearings 

Division (Departmental) of the Office 

of Hearings and Appeals, to stay the 

accrual of penalties pending the hearing on the record and a decision by the 

Administrative Law Judge under 

§250.1472. 

(1) You must file your petition within 

45 calendar days of receiving the Notice 

of Noncompliance. 

(2) To stay the accrual of penalties, 

you must post a bond or other surety 

instrument, or demonstrate financial 

solvency, using the standards and requirements as prescribed in §§250.1490 

through 250.1497, for the principal 

amount of any unpaid amounts due 

that are the subject of the Notice of 

Noncompliance, including interest 

thereon, plus the amount of any penalties accrued before the date a stay 

becomes effective. 

(3) The Hearings Division will grant 

or deny the petition under 43 CFR 

4.21(b). 

§ 250.1456 May I request a hearing on 

the record regarding the amount of 

a civil penalty if I did not request a 

hearing on the Notice of Noncompliance? 

(a) You may request a hearing on the 

record to challenge only the amount of 

a civil penalty when you receive a Notice of Civil Penalty, if you did not previously request a hearing on the record 

under §250.1454. If you did not request a 

hearing on the record on the Notice of 

Noncompliance under §250.1454, you 

may not contest your underlying liability for civil penalties. 

(b) You must file your request within 

10 days after you receive the Notice of 

Civil Penalty with the Hearings Division (Departmental), Office of Hearings 

and Appeals, U.S. Department of the 

Interior, 801 North Quincy Street, Arlington, Virginia 22203. 

PENALTIES WITHOUT A PERIOD TO

CORRECT

§ 250.1460 May I be subject to penalties without prior notice and an 

opportunity to correct? 

The Federal Oil and Gas Royalty 

Management Act sets out several specific violations for which penalties accrue without an opportunity to first 

correct the violation. 

(a) Under 30 U.S.C. 1719(c), you may 

be subject to penalties of up to $10,000 

per day per violation for each day the 

violation continues if you: 

(1) Fail or refuse to permit lawful 

entry, inspection, or audit; or 

(2) Knowingly or willfully fail or 

refuse to notify the Secretary, within 5 

business days after any well begins production on a lease site or allocated to 

a lease site, or resumes production in 

the case of a well which has been off 

production for more than 90 days, of 

the date on which production has 

begun or resumed. 

(b) Under 30 U.S.C. 1719(d), you may 

be subject to civil penalties of up to 

$25,000 per day for each day each violation continues if you: 

(1) Knowingly or willfully prepare, 

maintain, or submit false, inaccurate, 

or misleading reports, notices, affidavits, records, data, or other written information; 

(2) Knowingly or willfully take or remove, transport, use or divert any oil 

or gas from any lease site without having valid legal authority to do so; or 

(3) Purchase, accept, sell, transport, 

or convey to another person, any oil or 

gas knowing or having reason to know 

that such oil or gas was stolen or unlawfully removed or diverted. 

§ 250.1461 How will BSEE inform me of 

violations without a period to correct? 

We will inform you of any violation, 

without a period to correct, by issuing 

a Notice of Noncompliance and Civil 

Penalty explaining the violation, how 

to correct it, and the penalty assessment. We will serve the Notice of Noncompliance and Civil Penalty by registered mail or personal service using 


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Safety & Environmental Enforcement, Interior § 250.1473 

your address of record as specified 

under 30 CFR part 1218, Subpart H. 

§ 250.1462 How may I request a hearing on the record on a Notice of 

Noncompliance regarding violations without a period to correct? 

You may request a hearing on the 

record of a Notice of Noncompliance 

regarding violations without a period 

to correct by filing a request within 30 

days after you receive the Notice of 

Noncompliance with the Hearings Division (Departmental), Office of Hearings 

and Appeals, U.S. Department of the 

Interior, 801 North Quincy Street, Arlington, Virginia 22203. You may do 

this regardless of whether you correct 

the violations identified in the Notice 

of Noncompliance. 

§ 250.1463 Does my request for a hearing on the record affect the penalties? 

(a) If you do not correct the violations identified in the Notice of Noncompliance regarding violations without a period to correct, the penalties 

will continue to accrue even if you request a hearing on the record. 

(b) You may ask the Hearings Division (Departmental) to stay the accrual of penalties pending the hearing 

on the record and a decision by the Administrative Law Judge under 

§250.1472. 

(1) You must file your petition within 

45 calendar days after you receive the 

Notice of Noncompliance. 

(2) To stay the accrual of penalties, 

you must post a bond or other surety 

instrument, or demonstrate financial 

solvency, using the standards and requirements as prescribed in §§250.1490 

through 250.1497, for the principal 

amount of any unpaid amounts due 

that are the subject of the Notice of 

Noncompliance, including interest 

thereon, plus the amount of any penalties accrued before the date a stay 

becomes effective. 

(3) The Hearings Division will grant 

or deny the petition under 43 CFR 

4.21(b). 

§ 250.1464 May I request a hearing on 

the record regarding the amount of 

a civil penalty if I did not request a 

hearing on the Notice of Noncompliance? 

(a) You may request a hearing on the 

record to challenge only the amount of 

a civil penalty when you receive a Notice of Civil Penalty regarding violations without a period to correct, if 

you did not previously request a hearing on the record under §250.1462. If you 

did not request a hearing on the record 

on the Notice of Noncompliance under 

§250.1462, you may not contest your underlying liability for civil penalties. 

(b) You must file your request within 

10 days after you receive Notice of Civil 

Penalty with the Hearings Division 

(Departmental), Office of Hearings and 

Appeals, U.S. Department of the Interior, 801 North Quincy, Arlington, Virginia 22203. 

GENERAL PROVISIONS

§ 250.1470 How does BSEE decide what 

the amount of the penalty should 

be? 

We determine the amount of the penalty by considering the severity of the 

violations, your history of compliance, 

and if you are a small business. 

§ 250.1471 Does the penalty affect 

whether I owe interest? 

If you do not pay the penalty by the 

date required under §250.1475(d), BSEE 

will assess you late payment interest 

on the penalty amount at the same 

rate interest is assessed under 30 CFR 

1218.54. 

§ 250.1472 How will the Office of Hearings and Appeals conduct the hearing on the record? 

If you request a hearing on the 

record under §§250.1454, 250.1456, 

250.1462, or 250.1464, the hearing will be 

conducted by a Departmental Administrative Law Judge from the Office of 

Hearings and Appeals. After the hearing, the Administrative Law Judge will 

issue a decision in accordance with the 

evidence presented and applicable law. 

§ 250.1473 How may I appeal the Administrative Law Judge’s decision? 

If you are adversely affected by the 

Administrative Law Judge’s decision, 


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§ 250.1474 30 CFR Ch. II (7–1–13 Edition) 

you may appeal that decision to the Interior Board of Land Appeals under 43 

CFR part 4, subpart E. 

§ 250.1474 May I seek judicial review 

of the decision of the Interior 

Board of Land Appeals? 

Under 30 U.S.C. 1719(j), you may seek 

judicial review of the decision of the 

Interior Board of Land Appeals. A suit 

for judicial review in the District Court 

will be barred unless filed within 90 

days after the final order. 

§ 250.1475 When must I pay the penalty? 

(a) You must pay the amount of the 

Notice of Civil Penalty issued under 

§250.1453 or §250.1461, if you do not request a hearing on the record under 

§250.1454, §250.1456, §250.1462, or 

§250.1464. 

(b) If you request a hearing on the 

record under §§250.1454, 250.1456, 

250.1462, or 250.1464, but you do not appeal the determination of the Administrative Law Judge to the Interior 

Board of Land Appeals under §250.1473, 

you must pay the amount assessed by 

the Administrative Law Judge. 

(c) If you appeal the determination of 

the Administrative Law Judge to the 

Interior Board of Land Appeals, you 

must pay the amount assessed in the 

IBLA decision. 

(d) You must pay the penalty assessed within 40 days after: 

(1) You received the Notice of Civil 

Penalty, if you did not request a hearing on the record under either §250.1454, 

§250.1456, §250.1462, or §250.1464; 

(2) You received an Administrative 

Law Judge’s decision under §250.1472, if 

you obtained a stay of the accrual of 

penalties pending the hearing on the 

record under §250.1455(b) or §250.1463(b) 

and did not appeal the Administrative 

Law Judge’s determination to the 

IBLA under §250.1473; 

(3) You received an IBLA decision 

under §250.1473 if the IBLA continued 

the stay of accrual of penalties pending 

its decision and you did not seek judicial review of the IBLA’s decision; or 

(4) A final non-appealable judgment 

of a court of competent jurisdiction is 

entered, if you sought judicial review 

of the IBLA’s decision and the Department or the appropriate court suspended compliance with the IBLA’s decision pending the adjudication of the 

case. 

(e) If you do not pay, that amount is 

subject to collection under the provisions of §250.1477. 

§ 250.1476 Can BSEE reduce my penalty once it is assessed? 

Under 30 U.S.C. 1719(g), the Director 

or his or her delegate may compromise 

or reduce civil penalties assessed under 

this part. 

§ 250.1477 How may BSEE collect the 

penalty? 

(a) BSEE may use all available 

means to collect the penalty including, 

but not limited to: 

(1) Requiring the lease surety, for 

amounts owed by lessees, to pay the 

penalty; 

(2) Deducting the amount of the penalty from any sums the United States 

owes to you; and 

(3) Using judicial process to compel 

your payment under 30 U.S.C. 1719(k). 

(b) If the Department uses judicial 

process, or if you seek judicial review 

under §250.1474 and the court upholds 

assessment of a penalty, the court 

shall have jurisdiction to award the 

amount assessed plus interest assessed 

from the date of the expiration of the 

90-day period referred to in §250.1474. 

The amount of any penalty, as finally 

determined, may be deducted from any 

sum owing to you by the United States. 

CRIMINAL PENALTIES

§ 250.1480 May the United States 

criminally prosecute me for violations under Federal oil and gas 

leases? 

If you commit an act for which a 

civil penalty is provided at 30 U.S.C. 

1719(d) and §250.1460(b), the United 

States may pursue criminal penalties 

as provided at 30 U.S.C. 1720, in addition to any authority for prosecution 

under other statutes. 

BONDING REQUIREMENTS

§ 250.1490 What standards must my 

BOEM-specified surety instrument 

meet? 

(a) A BOEM-specified surety instrument must be in a form specified in 


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Safety & Environmental Enforcement, Interior § 250.1496 

BOEM instructions. BSEE will give 

you written information and standard 

forms for BOEM-specified surety instrument requirements. 

(b) BOEM will use a bank-rating service to determine whether a financial 

institution has an acceptable rating to 

provide a surety instrument adequate 

to indemnify the lessor from loss or 

damage. 

(1) Administrative appeal bonds must 

be issued by a qualified surety company which the Department of the 

Treasury has approved. 

(2) Irrevocable letters of credit or 

certificates of deposit must be from a 

financial institution acceptable to 

BOEM with a minimum 1-year period 

of coverage subject to automatic renewal up to 5 years. 

§ 250.1491 How will BOEM determine 

the amount of my bond or other 

surety instrument? 

(a) The BOEM bond-approving officer 

may approve your surety if he or she 

determines that the amount is adequate to guarantee payment. The 

amount of your surety may vary depending on the form of the surety and 

how long the surety is effective. 

(1) The amount of the BOEM-specified surety instrument must include 

the principal amount owed under the 

Notice of Noncompliance or Notice of 

Civil Penalty plus any accrued interest 

we determine is owed plus projected interest for a 1-year period. 

(2) Treasury book-entry bond or note 

amounts must be equal to at least 120 

percent of the required surety amount. 

(b) If your appeal is not decided within 1 year from the filing date, you must 

increase the surety amount to cover 

additional estimated interest for another 1-year period. You must continue 

to do this annually on the date your 

appeal was filed. We will determine the 

additional estimated interest and notify you of the amount so you can 

amend your surety instrument. 

(c) You may submit a single surety 

instrument that covers multiple appeals. You may change the instrument 

to add new amounts under appeal or remove amounts that have been adjudicated in your favor or that you have 

paid, if you: 

(1) Amend the single surety instrument annually on the date you filed 

your first appeal; and 

(2) Submit a separate surety instrument for new amounts under appeal 

until you amend the instrument to 

cover the new appeals. 

FINANCIAL SOLVENCY REQUIREMENTS

§ 250.1495 How do I demonstrate financial solvency? 

(a) To demonstrate financial solvency under this part, you must submit 

an audited consolidated balance sheet, 

and, if requested by the BOEM bond-approving officer, up to 3 years of tax returns to BOEM using the U.S. Postal 

Service, private delivery, courier, or 

overnight delivery at: 

(1) For Alaska OCS: Jeffrey Walker, 

RS/FO, BOEM Alaska OCS Region, 3801 

Centerpoint Drive, Suite 500, Anchorage, AK 99503–5823, jeffrey.walker@boem.gov, (907) 334–5300. 

(2) For Gulf of Mexico and Atlantic 

OCS: Joshua Joyce, Regional FARM 

Program Coordinator, BOEM Gulf of 

Mexico OCS Region, 1201 Elmwood 

Park Boulevard New Orleans, LA 70123– 

2394, joshua.joyce@boem.gov, (504) 736– 

2779. 

(3) For Pacific OCS: Jaron Ming, 

Lead Leasing Specialist, BOEM Pacific 

OCS Region, 770 Paseo Camarillo, 2nd 

Floor, Camarillo, CA 93010, 

jaron.ming@boem.gov, (805) 389–7514. 

(b) You must submit an audited consolidated balance sheet annually, and, 

if requested, additional annual tax returns on the date BSEE first determined that you demonstrated financial 

solvency as long as you have active appeals, or whenever BSEE requests. 

(c) If you demonstrate financial solvency in the current calendar year, you 

are not required to redemonstrate financial solvency for new appeals of orders during that calendar year unless 

you file for protection under any provision of the U.S. Bankruptcy Code (Title 

11 of the United States Code), or BSEE 

notifies you that you must redemonstrate financial solvency. 

§ 250.1496 How will BOEM determine 

if I am financially solvent? 

(a) The BOEM bond-approving officer 

will determine your financial solvency 


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§ 250.1497 30 CFR Ch. II (7–1–13 Edition) 

by examining your total net worth, including, as appropriate, the net worth 

of your affiliated entities. 

(b) If your net worth, minus the 

amount we would require as surety 

under §§250.1490 and 250.1491 for all orders you have appealed is greater than 

$300 million, you are presumptively 

deemed financially solvent, and we will 

not require you to post a bond or other 

surety instrument. 

(c) If your net worth, minus the 

amount we would require as surety 

under §§250.1490 and 250.1491 for all orders you have appealed is less than $300 

million, you must submit the following 

to BSEE by one of the methods in 

§250.1495(a): 

(1) A written request asking us to 

consult a business-information, or 

credit-reporting service or program to 

determine your financial solvency; and 

(2) A nonrefundable $50 processing 

fee: 

(i) You must pay the processing fee 

to us following the requirements for 

making payments found in 30 CFR 

250.126. You are required to use Electronic Funds Transfer (EFT) for these 

payments; 

(ii) You must submit the fee with 

your request under paragraph (c)(1) of 

this section, and then annually on the 

date we first determined that you demonstrated financial solvency, as long as 

you are not able to demonstrate financial solvency under paragraph (a) of 

this section and you have active appeals. 

(d) If you request that we consult a 

business-information or credit-reporting service or program under paragraph 

(c) of this section: 

(1) We will use criteria similar to 

that which a potential creditor would 

use to lend an amount equal to the 

bond or other surety instrument we 

would require under §§250.1490 and 

250.1491; 

(2) For us to consider you financially 

solvent, the business-information or 

credit-reporting service or program 

must demonstrate your degree of risk 

as low to moderate: 

(i) If our bond-approving officer determines that the business-information 

or credit-reporting service or program 

information demonstrates your financial solvency to our satisfaction, our 

bond-approving officer will not require 

you to post a bond or other surety instrument under §§250.1490 and 250.1491; 

(ii) If our bond-approving officer determines that the business-information 

or credit-reporting service or program 

information does not demonstrate your 

financial solvency to our satisfaction, 

our bond-approving officer will require 

you to post a bond or other surety instrument under §§250.1490 and 250.1491 

or pay the obligation. 

§ 250.1497 When will BOEM monitor 

my financial solvency? 

(a) If you are presumptively financially solvent under §250.1496(b), BOEM 

will determine your net worth as described under §250.1496(b) and (c) to 

evaluate your financial solvency at 

least annually on the date we first determined that you demonstrated financial solvency as long as you have active appeals and each time you appeal 

a new order. 

(b) If you ask us to consult a business-information or credit-reporting 

service or program under §250.1496(c), 

we will consult a service or program 

annually as long as you have active appeals and each time you appeal a new 

order. 

(c) If our bond-approving officer determines that you are no longer financially solvent, you must post a bond or 

other BOEM-specified surety instrument under §§250.1490 and 250.1491. 

Subpart O—Well Control and 

Production Safety Training 

§ 250.1500 Definitions. 

Terms used in this subpart have the 

following meaning: 

Contractor and contract personnel 

mean anyone, other than an employee 

of the lessee, performing well control, 

deepwater well control, or production 

safety duties for the lessee. 

Deepwater well control means well 

control when you are using a subsea 

BOP system. 

Employee means direct employees of 

the lessees who are assigned well control, deepwater well control, or production safety duties. 

I or you means the lessee engaged in 

oil, gas, or sulphur operations in the 

Outer Continental Shelf (OCS). 


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Safety & Environmental Enforcement, Interior § 250.1503 

Lessee means a person who has entered into a lease with the United 

States to explore for, develop, and 

produce the leased minerals. The term 

lessee also includes an owner of operating rights for that lease and the 

BOEM-approved assignee of that lease. 

Periodic means occurring or recurring 

at regular intervals. Each lessee must 

specify the intervals for periodic training and periodic assessment of training 

needs in their training programs. 

Production operations include, but are 

not limited to, separation, dehydration, compression, sweetening, and metering operations. 

Production safety includes measures, 

practices, procedures, and equipment 

to ensure safe, accident-free, and pollution-free production operations, as well 

as installation, repair, testing, maintenance, and operation of surface and 

subsurface safety equipment. 

Well completion/well workover means 

those operations following the drilling 

of a well that are intended to establish 

or restore production. 

Well-control means methods used to 

minimize the potential for the well to 

flow or kick and to maintain control of 

the well in the event of flow or a kick. 

Well-control applies to drilling, wellcompletion, well-workover, abandonment, and well-servicing operations. It 

includes measures, practices, procedures and equipment, such as fluid flow 

monitoring, to ensure safe and environmentally protective drilling, completion, abandonment, and workover operations as well as the installation, repair, maintenance, and operation of 

surface and subsea well-control equipment. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50896, Aug. 22, 2012] 

§ 250.1501 What is the goal of my training program? 

The goal of your training program 

must be safe and clean OCS operations. 

To accomplish this, you must ensure 

that your employees and contract personnel engaged in well control, deepwater well control, or production safety operations understand and can properly perform their duties. 

§ 250.1503 What are my general responsibilities for training? 

(a) You must establish and implement a training program so that all of 

your employees are trained to competently perform their assigned well 

control, deepwater well control, and 

production safety duties. You must 

verify that your employees understand 

and can perform the assigned well control, deepwater well control, or production safety duties. 

(b) If you conduct operations with a 

subsea BOP stack, your employees and 

contract personnel must be trained in 

deepwater well control. The trained 

employees and contract personnel must 

have a comprehensive knowledge of 

deepwater well control equipment, 

practices, and theory. 

(c) You must have a training plan 

that specifies the type, method(s), 

length, frequency, and content of the 

training for your employees. Your 

training plan must specify the method(s) of verifying employee understanding and performance. This plan 

must include at least the following information: 

(1) Procedures for training employees 

in well control, deepwater well control, 

or production safety practices; 

(2) Procedures for evaluating the 

training programs of your contractors; 

(3) Procedures for verifying that all 

employees and contractor personnel 

engaged in well control, deepwater well 

control, or production safety operations can perform their assigned duties; 

(4) Procedures for assessing the training needs of your employees on a periodic basis; 

(5) Recordkeeping and documentation procedures; and 

(6) Internal audit procedures. 

(d) Upon request of the District Manager or Regional Supervisor, you must 

provide: 

(1) Copies of training documentation 

for personnel involved in well control, 

deepwater well control, or production 

safety operations during the past 5 

years; and 

(2) A copy of your training plan. 


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§ 250.1504 30 CFR Ch. II (7–1–13 Edition) 

§ 250.1504 May I use alternative training methods? 

You may use alternative training 

methods. These methods may include 

computer-based learning, films, or 

their equivalents. This training should 

be reinforced by appropriate demonstrations and ‘‘hands-on’’ training. 

Alternative training methods must be 

conducted according to, and meet the 

objectives of, your training plan. 

§ 250.1505 Where may I get training for 

my employees? 

You may get training from any 

source that meets the requirements of 

your training plan. 

§ 250.1506 How often must I train my 

employees? 

You determine the frequency of the 

training you provide your employees. 

You must do all of the following: 

(a) Provide periodic training to ensure that employees maintain understanding of, and competency in, well 

control, deepwater well control, or production safety practices; 

(b) Establish procedures to verify 

adequate retention of the knowledge 

and skills that employees need to perform their assigned well control, deepwater well control, or production safety duties; and 

(c) Ensure that your contractors’ 

training programs provide for periodic 

training and verification of well control, deepwater well control, or production safety knowledge and skills. 

§ 250.1507 How will BSEE measure 

training results? 

BSEE may periodically assess your 

training program, using one or more of 

the methods in this section. 

(a) Training system audit. BSEE or its 

authorized representative may conduct 

a training system audit at your office. 

The training system audit will compare your training program against 

this subpart. You must be prepared to 

explain your overall training program 

and produce evidence to support your 

explanation. 

(b) Employee or contract personnel 

interviews. BSEE or its authorized representative may conduct interviews at 

either onshore or offshore locations to 

inquire about the types of training 

that were provided, when and where 

this training was conducted, and how 

effective the training was. 

(c) Employee or contract personnel testing. BSEE or its authorized representative may conduct testing at either onshore or offshore locations for the purpose of evaluating an individual’s 

knowledge and skills in perfecting well 

control, deepwater well control, and 

production safety duties. 

(d) Hands-on production safety, simulator, or live well testing. BSEE or its authorized representative may conduct 

tests at either onshore or offshore locations. Tests will be designed to evaluate the competency of your employees 

or contract personnel in performing 

their assigned well control, deepwater 

well control, and production safety duties. You are responsible for the costs 

associated with this testing, excluding 

salary and travel costs for BSEE personnel. 

§ 250.1508 What must I do when BSEE 

administers written or oral tests? 

BSEE or its authorized representative may test your employees or contract personnel at your worksite or at 

an onshore location. You and your contractors must: 

(a) Allow BSEE or its authorized representative to administer written or 

oral tests; and 

(b) Identify personnel by current position, years of experience in present 

position, years of total oil field experience, and employer’s name (e.g., operator, contractor, or sub-contractor 

company name). 

§ 250.1509 What must I do when BSEE 

administers or requires hands-on, 

simulator, or other types of testing? 

If BSEE or its authorized representative conducts, or requires you or your 

contractor to conduct hands-on, simulator, or other types of testing, you 

must: 

(a) Allow BSEE or its authorized representative to administer or witness 

the testing; 

(b) Identify personnel by current position, years of experience in present 

position, years of total oil field experience, and employer’s name (e.g., operator, contractor, or sub-contractor 

company name); and 


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(c) Pay for all costs associated with 

the testing, excluding salary and travel 

costs for BSEE personnel. 

§ 250.1510 What will BSEE do if my 

training program does not comply 

with this subpart? 

If BSEE determines that your training program is not in compliance, we 

may initiate one or more of the following enforcement actions: 

(a) Issue an Incident of Noncompliance (INC); 

(b) Require you to revise and submit 

to BSEE your training plan to address 

identified deficiencies; 

(c) Assess civil/criminal penalties; or 

(d) Initiate disqualification procedures. 

Subpart P—Sulphur Operations 

§ 250.1600 Performance standard. 

Operations to discover, develop, and 

produce sulphur in the OCS shall be in 

accordance with a BOEM-approved Exploration Plan or Development and 

Production Plan and shall be conducted in a manner to protect against 

harm or damage to life (including fish 

and other aquatic life), property, natural resources of the OCS including 

any mineral deposits (in areas leased or 

not leased), the National security or 

defense, and the marine, coastal, or 

human environment. 

§ 250.1601 Definitions. 

Terms used in this subpart shall have 

the meanings as defined below: 

Air line means a tubing string that is 

used to inject air within a sulphur producing well to airlift sulphur out of the 

well. 

Bleedwater means a mixture of mine 

water or booster water and connate 

water that is produced by a bleedwell. 

Bleedwell means a well drilled into a 

producing sulphur deposit that is used 

to control the mine pressure generated 

by the injection of mine water. 

Brine means the water containing 

dissolved salt obtained from a brine 

well by circulating water into and out 

of a cavity in the salt core of a salt 

dome. 

Brine well means a well drilled 

through cap rock into the core at a salt 

dome for the purpose of producing 

brine. 

Cap rock means the rock formation, a 

body of limestone, anhydride, and/or 

gypsum, overlying a salt dome. 

Sulphur deposit means a formation of 

rock that contains elemental sulphur. 

Sulphur production rate means the 

number of long tons of sulphur produced during a certain period of time, 

usually per day. 

§ 250.1602 Applicability. 

(a) The requirements of this subpart 

P are applicable to all exploration, development, and production operations 

under an OCS sulphur lease. Sulphur 

operations include all activities conducted under a lease for the purpose of 

discovery or delineation of a sulphur 

deposit and for the development and 

production of elemental sulphur. Sulphur operations also include activities 

conducted for related purposes. Activities conducted for related purposes include, but are not limited to, production of other minerals, such as salt, for 

use in the exploration for or the development and production of sulphur. The 

lessee must have obtained the right to 

produce and/or use these other minerals. 

(b) Lessees conducting sulphur operations in the OCS shall comply with 

the requirements of the applicable provisions of subparts A, B, C, I, J, M, N, 

O, and Q of this part and the applicable 

provisions of 30 CFR 550 subparts A, B, 

C, J and N. 

(c) Lessees conducting sulphur operations in the OCS are also required to 

comply with the requirements in the 

applicable provisions of subparts D, E, 

F, H, K, and L of this part and the applicable provisions of 30 CFR 550, subpart K, where such provisions specifically are referenced in this subpart. 

§ 250.1603 Determination of sulphur 

deposit. 

(a) Upon receipt of a written request 

from the lessee, the District Manager 

will determine whether a sulphur deposit has been defined that contains 

sulphur in paying quantities (i.e., sulphur in quantities sufficient to yield a 

return in excess of the costs, after completion of the wells, of producing minerals at the wellheads). 


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§ 250.1604 30 CFR Ch. II (7–1–13 Edition) 

(b) A determination under paragraph 

(a) of this section shall be based upon 

the following: 

(1) Core analyses that indicate the 

presence of a producible sulphur deposit (including an assay of elemental 

sulphur); 

(2) An estimate of the amount of recoverable sulphur in long tons over a 

specified period of time; and 

(3) Contour map of the cap rock together with isopach map showing the 

extent and estimated thickness of the 

sulphur deposit. 

§ 250.1604 General requirements. 

Sulphur lessees shall comply with requirements of this section when conducting well-drilling, well-completion, 

well-workover, or production operations. 

(a) Equipment movement. The movement of well-drilling, well-completion, 

or well-workover rigs and related 

equipment on and off an offshore platform, or from one well to another well 

on the same offshore platform, including rigging up and rigging down, shall 

be conducted in a safe manner. 

(b) Hydrogen sulfide (H2S). When a 

drilling, well-completion, wellworkover, or production operation is 

being conducted on a well in zones 

known to contain H2S or in zones 

where the presence of H2S is unknown 

(as defined in §250.490 of this part), the 

lessee shall take appropriate precautions to protect life and property, 

especially during operations such as 

dismantling wellhead equipment and 

flow lines and circulating the well. The 

lessee shall also take appropriate precautions when H2S is generated as a result of sulphur production operations. 

The lessee shall comply with the requirements in §250.490 of this part as 

well as the requirements of this subpart. 

(c) Welding and burning practices and 

procedures. All welding, burning, and 

hot-tapping activities involved in drilling, well-completion, well-workover or 

production operations shall be conducted with properly maintained equipment, trained personnel, and appropriate procedures in order to minimize 

the danger to life and property according to the specific requirements in 

§§250.109 through 250.113 of this part. 

(d) Electrical requirements. All electrical equipment and systems involved 

in drilling, well-completion, wellworkover, and production operations 

shall be designed, installed, equipped, 

protected, operated, and maintained so 

as to minimize the danger to life and 

property in accordance with the requirements of §250.114 of this part. 

(e) Structures on fixed OCS platforms. 

Derricks, cranes, masts, substructures, 

and related equipment shall be selected, designed, installed, used, and 

maintained so as to be adequate for the 

potential loads and conditions of loading that may be encountered during 

the operations. Prior to moving equipment such as a well-drilling, well-completion, or well-workover rig or associated equipment or production equipment onto a platform, the lessee shall 

determine the structural capability of 

the platform to safely support the 

equipment and operations, taking into 

consideration corrosion protection, 

platform age, and previous stresses. 

(f) Traveling-block safety device. All 

drilling units being used for drilling, 

well-completion, or well-workover operations that have both a traveling 

block and a crown block must be 

equipped with a safety device that is 

designed to prevent the traveling block 

from striking the crown block. The device must be checked for proper operation weekly and after each drill-line 

slipping operation. The results of the 

operational check must be entered in 

the operations log. 

§ 250.1605 Drilling requirements. 

(a) Sulphur leases. Lessees of OCS sulphur leases shall conduct drilling operations in accordance with §§250.1605 

through 250.1619 of this subpart and 

with other requirements of this part, 

as appropriate. 

(b) Fitness of drilling unit. (1) Drilling 

units shall be capable of withstanding 

the oceanographic and meteorological 

conditions for the proposed season and 

location of operations. 

(2) Prior to commencing operation, 

drilling units shall be made available 

for a complete inspection by the District Manager. 

(3) The lessee shall provide information and data on the fitness of the 

drilling unit to perform the proposed 


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Safety & Environmental Enforcement, Interior § 250.1605 

drilling operation. The information 

shall be submitted with, or prior to, 

the submission of Form BSEE–0123, Application for Permit to Drill (APD), in 

accordance with §250.1617 of this subpart. After a drilling unit has been approved by a BSEE district office, the 

information required in this paragraph 

need not be resubmitted unless required by the District Manager or 

there are changes in the equipment 

that affect the rated capacity of the 

unit. 

(c) Oceanographic, meteorological, and 

drilling unit performance data. Where 

oceanographic, meteorological, and 

drilling unit performance data are not 

otherwise readily available, lessees 

shall collect and report such data upon 

request to the District Manager. The 

type of information to be collected and 

reported will be determined by the District Manager in the interests of safety 

in the conduct of operations and the 

structural integrity of the drilling 

unit. 

(d) Foundation requirements. When the 

lessee fails to provide sufficient information pursuant to 30 CFR 550.211 

through 550.228 and 30 CFR 550.241 

through 550.262 to support a determination that the seafloor is capable of supporting a specific bottom-founded drilling unit under the site-specific soil and 

oceanographic conditions, the District 

Manager may require that additional 

surveys and soil borings be performed 

and the results submitted for review 

and evaluation by the District Manager 

before approval is granted for commencing drilling operations. 

(e) Tests, surveys, and samples. (1) Lessees shall drill and take cores and/or 

run well and mud logs through the objective interval to determine the presence, quality, and quantity of sulphur 

and other minerals (e.g., oil and gas) in 

the cap rock and the outline of the 

commercial sulphur deposit. 

(2) Inclinational surveys shall be obtained on all vertical wells at intervals 

not exceeding 1,000 feet during the normal course of drilling. Directional surveys giving both inclination and azimuth shall be obtained on all directionally drilled wells at intervals not 

exceeding 500 feet during the normal 

course of drilling and at intervals not 

exceeding 200 feet in all planned anglechange portions of the borehole. 

(3) Directional surveys giving both 

inclination and azimuth shall be obtained on both vertically and directionally drilled wells at intervals not 

exceeding 500 feet prior to or upon setting a string of casing, or production 

liner, and at total depth. Composite directional surveys shall be prepared 

with the interval shown from the bottom of the conductor casing. In calculating all surveys, a correction from 

the true north to Universal-Transverse-Mercator-Grid-north or LambertGrid-north shall be made after making 

the magnetic-to-true-north correction. 

A composite dipmeter directional survey or a composite measurement 

while-drilling directional survey will 

be acceptable as fulfilling the applicable requirements of this paragraph. 

(4) Wells are classified as vertical if 

the calculated average of inclination 

readings weighted by the respective interval lengths between readings from 

surface to drilled depth does not exceed 

3 degrees from the vertical. When the 

calculated average inclination readings 

weighted by the length of the respective interval between readings from the 

surface to drilled depth exceeds 3 degrees, the well is classified as directional. 

(5) At the request of a holder of an 

adjoining lease, the Regional Supervisor may, for the protection of correlative rights, furnish a copy of the directional survey to that leaseholder. 

(f) Fixed drilling platforms. Applications for installation of fixed drilling 

platforms or structures including artificial islands shall be submitted in accordance with the provisions of subpart 

I, Platforms and Structures, of this 

part. Mobile drilling units that have 

their jacking equipment removed or 

have been otherwise immobilized are 

classified as fixed bottom founded drilling platforms. 

(g) Crane operations. You must operate a crane installed on fixed platforms 

according to §250.108 of this subpart. 

(h) Diesel-engine air intakes. Diesel-engine air intakes must be equipped with 

a device to shut down the diesel engine 

in the event of runaway. Diesel engines 

that are continuously attended must 


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§ 250.1606 30 CFR Ch. II (7–1–13 Edition) 

be equipped with either remote-operated manual or automatic-shutdown 

devices. Diesel engines that are not 

continuously attended must be 

equipped with automatic shutdown devices. 

§ 250.1606 Control of wells. 

The lessee shall take necessary precautions to keep its wells under control at all times. Operations shall be 

conducted in a safe and workmanlike 

manner. The lessee shall utilize the 

best available and safest drilling technologies and state-of-the-art methods 

to evaluate and minimize the potential 

for a well to flow or kick. The lessee 

shall utilize personnel who are trained 

and competent and shall utilize and 

maintain equipment and materials necessary to assure the safety and protection of personnel, equipment, natural 

resources, and the environment. 

§ 250.1607 Field rules. 

When geological and engineering information in a field enables a District 

Manager to determine specific operating requirements, field rules may be 

established for drilling, well completion, or well workover on the District 

Manager’s initiative or in response to a 

request from a lessee; such rules may 

modify the specific requirements of 

this subpart. After field rules have 

been established, operations in the 

field shall be conducted in accordance 

with such rules and other requirements 

of this subpart. Field rules may be 

amended or canceled for cause at any 

time upon the initiative of the District 

Manager or upon the request of a lessee. 

§ 250.1608 Well casing and cementing. 

(a) General requirements. (1) For the 

purpose of this subpart, the several 

casing strings in order of normal installation are: 

(i) Drive or structural, 

(ii) Conductor, 

(iii) Cap rock casing, 

(iv) Bobtail cap rock casing (required 

when the cap rock casing does not penetrate into the cap rock), 

(v) Second cap rock casing (brine 

wells), and 

(vi) Production liner. 

(2) The lessee shall case and cement 

all wells with a sufficient number of 

strings of casing cemented in a manner 

necessary to prevent release of fluids 

from any stratum through the wellbore 

(directly or indirectly) into the sea, 

protect freshwater aquifers from contamination, support unconsolidated 

sediments, and otherwise provide a 

means of control of the formation pressures and fluids. Cement composition, 

placement techniques, and waiting 

time shall be designed and conducted 

so that the cement in place behind the 

bottom 500 feet of casing or total 

length of annular cement fill, if less, 

attains a minimum compressive 

strength of 160 pounds per square inch 

(psi). 

(3) The lessee shall install casing designed to withstand the anticipated 

stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and 

combinations thereof. Safety factors in 

the drilling and casing program designs 

shall be of sufficient magnitude to provide well control during drilling and to 

assure safe operations for the life of 

the well. 

(4) In cases where cement has filled 

the annular space back to the mud 

line, the cement may be washed out or 

displaced to a depth not exceeding the 

depth of the structural casing shoe to 

facilitate casing removal upon well 

abandonment if the District Manager 

determines that subsurface protection 

against damage to freshwater aquifers 

and against damage caused by adverse 

loads, pressures, and fluid flows is not 

jeopardized. 

(5) If there are indications of inadequate cementing (such as lost returns, 

cement channeling, or mechanical failure of equipment), the lessee shall 

evaluate the adequacy of the cementing operations by pressure testing the 

casing shoe. If the test indicates inadequate cementing, the lessee shall initiate remedial action as approved by 

the District Manager. For cap rock casing, the test for adequacy of cementing 

shall be the pressure testing of the annulus between the cap rock and the 

conductor casings. The pressure shall 


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Safety & Environmental Enforcement, Interior § 250.1609 

not exceed 70 percent of the burst pressure of the conductor casing or 70 percent of the collapse pressure of the cap 

rock casing. 

(b) Drive or structural casing. This casing shall be set by driving, jetting, or 

drilling to a minimum depth of 100 feet 

below the mud line or such other 

depth, as may be required or approved 

by the District Manager, in order to 

support unconsolidated deposits and to 

provide hole stability for initial drilling operations. If this portion of the 

hole is drilled, a quantity of cement 

sufficient to fill the annular space back 

to the mud line shall be used. 

(c) Conductor and cap rock casing setting and cementing requirements. (1) Conductor and cap rock casing design and 

setting depths shall be based upon relevant engineering and geologic factors 

including the presence or absence of 

hydrocarbons, potential hazards, and 

water depths. The proposed casing setting depths may be varied, subject to 

District Manager approval, to permit 

the casing to be set in a competent formation or through formations determined desirable to be isolated from the 

wellbore by casing for safer drilling operations. However, the conductor casing shall be set immediately prior to 

drilling into formations known to contain oil or gas or, if unknown, upon encountering such formations. Cap rock 

casing shall be set and cemented 

through formations known to contain 

oil or gas or, if unknown, upon encountering such formations. Upon encountering unexpected formation pressures, 

the lessee shall submit a revised casing 

program to the District Manager for 

approval. 

(2) Conductor casing shall be cemented with a quantity of cement that 

fills the calculated annular space back 

to the mud line. Cement fill shall be 

verified by the observation of cement 

returns. In the event that observation 

of cement returns is not feasible, additional quantities of cement shall be 

used to assure fill to the mud line. 

(3) Cap rock casing shall be cemented 

with a quantity of cement that fills the 

calculated annular space to at least 200 

feet inside the conductor casing. When 

geologic conditions such as near surface fractures and faulting exist, cap 

rock casing shall be cemented with a 

quantity of cement that fills the calculated annular space to the mud line, 

unless otherwise approved by the District Manager. In brine wells, the second cap rock casing shall be cemented 

with a quantity of cement that fills the 

calculated annular space to at least 200 

feet above the setting depth of the first 

cap rock casing. 

(d) Bobtail cap rock casing setting and 

cementing requirements. (1) Bobtail cap 

rock casing shall be set on or just in 

cap rock and lapped a minimum of 100 

feet into the previous casing string. 

(2) Sufficient cement shall be used to 

fill the annular space to the top of the 

bobtail cap rock casing. 

(e) Production liner setting and cementing requirements. (1) Production liners 

for sulphur wells and bleedwells shall 

be set in cap rock at or above the bottom of the open hole (hole that is open 

in cap rock, below the bottom of the 

cap rock casing) and lapped into the 

previous casing string or to the surface. For brine wells, the liner shall be 

set in salt and lapped into the previous 

casing string or to the surface. 

(2) The production liner is not required to be cemented unless the cap 

rock contains oil or gas. If the cap rock 

contains oil or gas, sufficient cement 

shall be used to fill the annular space 

to the top of the production liner. 

§ 250.1609 Pressure testing of casing. 

(a) Prior to drilling the plug after cementing, all casing strings, except the 

drive or structural casing, shall be 

pressure tested. The conductor casing 

shall be tested to at least 200 psi. All 

casing strings below the conductor casing shall be tested to 500 psi or 0.22 psi/ 

ft, whichever is greater. (When oil or 

gas is not present in the cap rock, the 

production liner need not be cemented 

in place; thus, it would not be subject 

to pressure testing.) If the pressure declines more than 10 percent in 30 minutes or if there is another indication of 

a leak, the casing shall be recemented, 

repaired, or an additional casing string 

run and the casing tested again. The 

above procedures shall be repeated 

until a satisfactory test is obtained. 

The time, conditions of testing, and results of all casing pressure tests shall 

be recorded in the driller’s report. 


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§ 250.1610 30 CFR Ch. II (7–1–13 Edition) 

(b) After cementing any string of casing other than structural, drilling shall 

not be resumed until there has been a 

timelapse of at least 8 hours under 

pressure for the conductor casing 

string or 12 hours under pressure for all 

other casing strings. Cement is considered under pressure if one or more float 

valves are shown to be holding the cement in place or when other means of 

holding pressure are used. 

§ 250.1610 Blowout preventer systems 

and system components. 

(a) General. The blowout preventer 

(BOP) systems and system components 

shall be designed, installed, used, 

maintained, and tested to assure well 

control. 

(b) BOP stacks. The BOP stacks shall 

consist of an annular preventer and the 

number of ram-type preventers as specified under paragraphs (e) and (f) of 

this section. The pipe rams shall be of 

proper size to fit the drill pipe in use. 

(c) Working pressure. The workingpressure rating of any BOP shall exceed the surface pressure to which it 

may be anticipated to be subjected. 

(d) BOP equipment. All BOP systems 

shall be equipped and provided with the 

following: 

(1) An accumulator system that provides sufficient capacity to supply 1.5 

times the volume necessary to close 

and hold closed all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure, without assistance from a charging system. 

Accumulator regulators supplied by rig 

air that do not have a secondary source 

of pneumatic supply must be equipped 

with manual overrides or other devices 

alternately provided to ensure capability of hydraulic operations if rig air 

is lost. 

(2) An automatic backup to the accumulator system. The backup system 

shall be supplied by a power source 

independent from the power source to 

the primary accumulator system. The 

automatic backup system shall possess 

sufficient capability to close the BOP 

and hold it closed. 

(3) At least one operable remote BOP 

control station in addition to the one 

on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor. 

(4) A drilling spool with side outlets, 

if side outlets are not provided in the 

body of the BOP stack, to provide for 

separate kill and choke lines. 

(5) A choke line and a kill line each 

equipped with two full-opening valves. 

At least one of the valves on the choke 

line and one valve on the kill line shall 

be remotely controlled, except that a 

check valve may be installed on the 

kill line in lieu of the remotely controlled valve, provided that two readily 

accessible manual valves are in place 

and the check valve is placed between 

the manual valve and the pump. 

(6) A fill-up line above the uppermost 

preventer. 

(7) A choke manifold designed with 

consideration of anticipated pressures 

to which it may be subjected, method 

of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness of 

fluids. The choke manifold shall also 

meet the following requirements: 

(i) Manifold and choke equipment 

subject to well and/or pump pressure 

shall have a rated working pressure at 

least as great as the rated working 

pressure of the ram-type BOP’s or as 

otherwise approved by the District 

Manager; 

(ii) All components of the choke 

manifold system shall be protected 

from freezing by heating, draining, or 

filling with proper fluids; and 

(iii) When buffer tanks are installed 

downstream of the choke assemblies 

for the purpose of manifolding the 

bleed lines together, isolation valves 

shall be installed on each line. 

(8) Valves, pipes, flexible steel hoses, 

and other fittings upstream of, and including, the choke manifold with a 

pressure rating at least as great as the 

rated working pressure of the ram-type 

BOP’s unless otherwise approved by 

the District Manager. 

(9) A wellhead assembly with a rated 

working pressure that exceeds the pressure to which it might be subjected. 

(10) The following system components: 

(i) A kelly cock (an essentially fullopening valve) installed below the 

swivel and a similar valve of such design that it can be run through the 

BOP stack installed at the bottom of 

the kelly. A wrench to fit each valve 


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Safety & Environmental Enforcement, Interior § 250.1611 

shall be stored in a location readily accessible to the drilling crew; 

(ii) An inside BOP and an essentially 

full-opening, drill-string safety valve 

in the open position on the rig floor at 

all times while drilling operations are 

being conducted. These valves shall be 

maintained on the rig floor to fit all 

connections that are in the drill string. 

A wrench to fit the drill-string safety 

valve shall be stored in a location readily accessible to the drilling crew; 

(iii) A safety valve available on the 

rig floor assembled with the proper 

connection to fit the casing string 

being run in the hole; and 

(iv) Locking devices installed on the 

ram-type preventers. 

(e) BOP requirements. Prior to drilling 

below cap rock casing, a BOP system 

shall be installed consisting of at least 

three remote-controlled, hydraulically 

operated BOP’s including at least one 

equipped with pipe rams, one with 

blind rams, and one annular type. 

(f) Tapered drill-string operations. 

Prior to commencing tapered drillstring operations, the BOP stack shall 

be equipped with conventional and/or 

variable-bore pipe rams to provide either of the following: 

(1) One set of variable bore rams capable of sealing around both sizes in 

the string and one set of blind rams, or 

(2) One set of pipe rams capable of 

sealing around the larger size string, 

provided that blind-shear ram capability is present, and crossover subs to 

the larger size pipe are readily available on the rig floor. 

§ 250.1611 Blowout preventer systems 

tests, actuations, inspections, and 

maintenance. 

(a) Prior to conducting high-pressure 

tests, all BOP systems shall be tested 

to a pressure of 200 to 300 psi. 

(b) Ram-type BOP’s and the choke 

manifold shall be pressure tested with 

water to rated working pressure or as 

otherwise approved by the District 

Manager. Annular type BOP’s shall be 

pressure tested with water to 70 percent of rated working pressure or as 

otherwise approved by the District 

Manager. 

(c) In conjunction with the weekly 

pressure test of BOP systems required 

in paragraph (d) of this section, the 

choke manifold valves, upper and lower 

kelly cocks, and drill-string safety 

valves shall be pressure tested to piperam test pressures. Safety valves with 

proper casing connections shall be actuated prior to running casing. 

(d) BOP system shall be pressure 

tested as follows: 

(1) When installed; 

(2) Before drilling out each string of 

casing or before continuing operations 

in cases where cement is not drilled 

out; 

(3) At least once each week, but not 

exceeding 7 days between pressure 

tests, alternating between control stations. If either control system is not 

functional, further drilling operations 

shall be suspended until that system 

becomes operable. A period of more 

than 7 days between BOP tests is allowed when there is a stuck drill pipe 

or there are pressure control operations and remedial efforts are being 

performed, provided that the pressure 

tests are conducted as soon as possible 

and before normal operations resume. 

The date, time, and reason for postponing pressure testing shall be entered into the driller’s report. Pressure 

testing shall be performed at intervals 

to allow each drilling crew to operate 

the equipment. The weekly pressure 

test is not required for blind and blindshear rams; 

(4) Blind and blind-shear rams shall 

be actuated at least once every 7 days. 

Closing pressure on the blind and blindshear rams greater than necessary to 

indicate proper operation of the rams 

is not required; 

(5) Variable bore-pipe rams shall be 

pressure tested against all sizes of pipe 

in use, excluding drill collars and 

bottomhole tools; and 

(6) Following the disconnection or repair of any well-pressure containment 

seal in the wellhead/BOP stack assembly. In this situation, the pressure 

tests may be limited to the affected 

component. 

(e) All BOP systems shall be inspected and maintained to assure that 

the equipment will function properly. 

The BOP systems shall be visually inspected at least once each day. The 

manufacturer’s recommended inspection and maintenance procedures are 


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§ 250.1612 30 CFR Ch. II (7–1–13 Edition) 

acceptable as guidelines in complying 

with this requirement. 

(f) The lessee shall record pressure 

conditions during BOP tests on pressure charts, unless otherwise approved 

by the District Manager. The test duration for each BOP component tested 

shall be sufficient to demonstrate that 

the component is effectively holding 

pressure. The charts shall be certified 

as correct by the operator’s representative at the facility. 

(g) The time, date, and results of all 

pressure tests, actuations, inspections, 

and crew drills of the BOP system and 

system components shall be recorded 

in the driller’s report. The BOP tests 

shall be documented in accordance 

with the following: 

(1) The documentation shall indicate 

the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an 

alternate, the documentation in the 

driller’s report may reference a BOP 

test plan that contains the required information and is retained on file at the 

facility. 

(2) The control station used during 

the test shall be identified in the 

driller’s report. 

(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to 

remedy such problems or irregularities 

shall be noted in the driller’s report. 

(4) Documentation required to be entered in the driller’s report may instead be referenced in the driller’s report. All records, including pressure 

charts, driller’s report, and referenced 

documents, pertaining to BOP tests, 

actuations, and inspections, shall be 

available for BSEE review at the facility for the duration of the drilling activity. Following completion of the 

drilling activity, all drilling records 

shall be retained for a period of 2 years 

at the facility, at the lessee’s field office nearest the OCS facility, or at another location conveniently available 

to the District Manager. 

§ 250.1612 Well-control drills. 

Well-control drills shall be conducted 

for each drilling crew in accordance 

with the requirements set forth in 

§250.462 of this part or as approved by 

the District Manager. 

§ 250.1613 Diverter systems. 

(a) When drilling a conductor or cap 

rock hole, all drilling units shall be 

equipped with a diverter system consisting of a diverter sealing element, 

diverter lines, and control systems. 

The diverter system shall be designed, 

installed, and maintained so as to divert gases, water, mud, and other materials away from the facilities and 

personnel. 

(b) The diverter system shall be 

equipped with remote-control valves in 

the flow lines that can be operated 

from at least one remote-control station in addition to the one on the drilling floor. Any valve used in a diverter 

system shall be full opening. No manual or butterfly valves shall be installed in any part of a diverter system. There shall be a minimum number 

of turns in the vent line(s) downstream 

of the spool outlet flange, and the radius of curvature of turns shall be as 

large as practicable. Flexible hose may 

be used for diversion lines instead of 

rigid pipe if the flexible hose has integral end couplings. The entire diverter 

system shall be firmly anchored and 

supported to prevent whipping and vibrations. All diverter control equipment and lines shall be protected from 

physical damage from thrown and falling objects. 

(c) For drilling operations conducted 

with a surface wellhead configuration, 

the following shall apply: 

(1) If the diverter system utilizes 

only one spool outlet, branch lines 

shall be installed to provide downwind 

diversion capability, and 

(2) No spool outlet or diverter line internal diameter shall be less than 10 

inches, except that dual spool outlets 

are acceptable if each outlet has a minimum internal diameter of 8 inches, 

and both outlets are piped to overboard 

lines and that each line downstream of 

the changeover nipple at the spool has 

a minimum internal diameter of 10 

inches. 

(d) The diverter sealing element and 

diverter valves shall be pressure tested 

to a minimum of 200 psi when nippled 

upon conductor casing. No more than 7 

days shall elapse between subsequent 

pressure tests. The diverter sealing element, diverter valves, and diverter control systems (including the remote) 


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Safety & Environmental Enforcement, Interior § 250.1617 

shall be actuation tested, and the diverter lines shall be tested for flow 

prior to spudding and thereafter at 

least once each 24-hour period alternating between control stations. All 

test times and results shall be recorded 

in the driller’s report. 

§ 250.1614 Mud program. 

(a) The quantities, characteristics, 

use, and testing of drilling mud and the 

related drilling procedures shall be designed and implemented to prevent the 

loss of well control. 

(b) The lessee shall comply with requirements concerning mud control, 

mud test and monitoring equipment, 

mud quantities, and safety precautions 

in enclosed mud handling areas as prescribed in §§250.455 through 250.459 of 

this part, except that the installation 

of an operable degasser in the mud system as required in §250.456(g) is not required for sulphur operations. 

§ 250.1615 Securing of wells. 

A downhole-safety device such as a 

cement plug, bridge plug, or packer 

shall be timely installed when drilling 

operations are interrupted by events 

such as those that force evacuation of 

the drilling crew, prevent station keeping, or require repairs to major drilling 

units or well-control equipment. The 

use of blind-shear rams or pipe rams 

and an inside BOP may be approved by 

the District Manager in lieu of the 

above requirements if cap rock casing 

has been set. 

§ 250.1616 Supervision, surveillance, 

and training. 

(a) The lessee shall provide onsite supervision of drilling operations at all 

times. 

(b) From the time drilling operations 

are initiated and until the well is completed or abandoned, a member of the 

drilling crew or the toolpusher shall 

maintain rig-floor surveillance continuously, unless the well is secured 

with BOP’s, bridge plugs, packers, or 

cement plugs. 

(c) Lessee and drilling contractor 

personnel shall be trained and qualified 

in accordance with the provisions of 

subpart O of this part. Records of specific training that lessee and drilling 

contractor personnel have successfully 

completed, the dates of completion, 

and the names and dates of the courses 

shall be maintained at the drill site. 

§ 250.1617 Application for permit to 

drill. 

(a) Before drilling a well under a 

BOEM-approved Exploration Plan, Development and Production Plan, or Development Operations Coordination 

Document, you must file Form BSEE– 

0123, APD, with the District Manager 

for approval. The submission of your 

APD must be accompanied by payment 

of the service fee listed in §250.125. Before starting operations, you must receive written approval from the District Manager unless you received oral 

approval under §250.140. 

(b) An APD shall include rated capacities of the proposed drilling unit and 

of major drilling equipment. After a 

drilling unit has been approved for use 

in a BSEE district, the information 

need not be resubmitted unless required by the District Manager or 

there are changes in the equipment 

that affect the rated capacity of the 

unit. 

(c) An APD shall include a fully completed Form BSEE–0123 and the following: 

(1) A plat, drawn to a scale of 2,000 

feet to the inch, showing the surface 

and subsurface location of the well to 

be drilled and of all the wells previously drilled in the vicinity from 

which information is available. For development wells on a lease, the wells 

previously drilled in the vicinity need 

not be shown on the plat. Locations 

shall be indicated in feet from the 

nearest block line; 

(2) The design criteria considered for 

the well and for well control, including 

the following: 

(i) Pore pressure; 

(ii) Formation fracture gradients; 

(iii) Potential lost circulation zones; 

(iv) Mud weights; 

(v) Casing setting depths; 

(vi) Anticipated surface pressures 

(which for purposes of this section are 

defined as the pressure that can reasonably be expected to be exerted upon 

a casing string and its related wellhead 

equipment). In the calculation of anticipated surface pressure, the lessee 

shall take into account the drilling, 


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§ 250.1618 30 CFR Ch. II (7–1–13 Edition) 

completion, and producing conditions. 

The lessee shall consider mud densities 

to be used below various casing strings, 

fracture gradients of the exposed formations, casing setting depths, and cementing intervals, total well depth, 

formation fluid type, and other pertinent conditions. Considerations for calculating anticipated surface pressure 

may vary for each segment of the well. 

The lessee shall include as a part of the 

statement of anticipated surface pressure the calculations used to determine 

this pressure during the drilling phase 

and the completion phase, including 

the anticipated surface pressure used 

for production string design; and 

(vii) If a shallow hazards site survey 

is conducted, the lessee shall submit 

with or prior to the submittal of the 

APD, two copies of a summary report 

describing the geological and manmade 

conditions present. The lessee shall 

also submit two copies of the site maps 

and data records identified in the survey strategy. 

(3) A BOP equipment program including the following: 

(i) The pressure rating of BOP equipment, 

(ii) A schematic drawing of the diverter system to be used (plan and elevation views) showing spool outlet internal diameter(s); diverter line 

lengths and diameters, burst strengths, 

and radius of curvature at each turn; 

valve type, size, working-pressure rating, and location; the control instrumentation logic; and the operating procedure to be used by personnel, and 

(iii) A schematic drawing of the BOP 

stack showing the inside diameter of 

the BOP stack and the number of annular, pipe ram, variable-bore pipe ram, 

blind ram, and blind-shear ram preventers. 

(4) A casing program including the 

following: 

(i) Casing size, weight, grade, type of 

connection and setting depth, and 

(ii) Casing design safety factors for 

tension, collapse, and burst with the 

assumptions made to arrive at these 

values. 

(5) The drilling prognosis including 

the following: 

(i) Estimated coring intervals, 

(ii) Estimated depths to the top of 

significant marker formations, and 

(iii) Estimated depths at which encounters with fresh water, sulphur, oil, 

gas, or abnormally pressured water are 

expected. 

(6) A cementing program including 

type and amount of cement in cubic 

feet to be used for each casing string; 

(7) A mud program including the 

minimum quantities of mud and mud 

materials, including weight materials, 

to be kept at the site; 

(8) A directional survey program for 

directionally drilled wells; 

(9) An H2S Contingency Plan, if applicable, and if not previously submitted; 

and 

(10) Such other information as may 

be required by the District Manager. 

(d) Public information copies of the 

APD shall be submitted in accordance 

with §250.186 of this part. 

§ 250.1618 Application for permit to 

modify. 

(a) You must submit requests for 

changes in plans, changes in major 

drilling equipment, proposals to deepen, sidetrack, complete, workover, or 

plug back a well, or engage in similar 

activities to the District Manager on 

Form BSEE–0124, Application for Permit to Modify (APM). The submission 

of your APM must be accompanied by 

payment of the service fee listed in 

§250.125. Before starting operations associated with the change, you must receive written approval from the District Manager unless you received oral 

approval under §250.140. 

(b) The Form BSEE–0124 submittal 

shall contain a detailed statement of 

the proposed work that will materially 

change from the work described in the 

approved APD. Information submitted 

shall include the present state of the 

well, including the production liner 

and last string of casing, the well depth 

and production zone, and the well’s capability to produce. Within 30 days 

after completion of the work, a subsequent detailed report of all the work 

done and the results obtained shall be 

submitted. 

(c) Public information copies of Form 

BSEE–0124 shall be submitted in accordance with §250.186 of this part. 


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Safety & Environmental Enforcement, Interior § 250.1622 

§ 250.1619 Well records. 

(a) Complete and accurate records for 

each well and all well operations shall 

be retained for a period of 2 years at 

the lessee’s field office nearest the OCS 

facility or at another location conveniently available to the District Manager. The records shall contain a description of any significant malfunction or problem; all the formations 

penetrated; the content and character 

of sulphur in each formation if cored 

and analyzed; the kind, weight, size, 

grade, and setting depth of casing; all 

well logs and surveys run in the 

wellbore; and all other information required by the District Manager in the 

interests of resource evaluation, prevention of waste, conservation of natural resources, protection of correlative rights, safety of operations, and 

environmental protection. 

(b) When drilling operations are suspended or temporarily prohibited under 

the provisions of §250.170 of this part, 

the lessee shall, within 30 days after 

termination of the suspension or temporary prohibition or within 30 days 

after the completion of any activities 

related to the suspension or prohibition, transmit to the District Manager 

duplicate copies of the records of all 

activities related to and conducted during the suspension or temporary prohibition on, or attached to, Form BSEE– 

0125, End of Operations Report, or 

Form BSEE–0124, Application for Permit to Modify, as appropriate. 

(c) Upon request by the District Manager or Regional Supervisor, the lessee 

shall furnish the following: 

(1) Copies of the records of any of the 

well operations specified in paragraph 

(a) of this section; 

(2) Copies of the driller’s report at a 

frequency as determined by the District Manager. Items to be reported include spud dates, casing setting depths, 

cement quantities, casing characteristics, mud weights, lost returns, and 

any unusual activities; and 

(3) Legible, exact copies of reports on 

cementing, acidizing, analyses of cores, 

testing, or other similar services. 

(d) As soon as available, the lessee 

shall transmit copies of logs and charts 

developed by well-logging operations, 

directional-well surveys, and core analyses. Composite logs of multiple runs 

and directional-well surveys shall be 

transmitted to the District Manager in 

duplicate as soon as available but not 

later than 30 days after completion of 

such operations for each well. 

(e) If the District Manager determines that circumstances warrant, the 

lessee shall submit any other reports 

and records of operations in the manner and form prescribed by the District 

Manager. 

§ 250.1620 Well-completion and wellworkover requirements. 

(a) Lessees shall conduct well-completion and well-workover operations 

in sulphur wells, bleedwells, and brine 

wells in accordance with §§250.1620 

through 250.1626 of this part and other 

provisions of this part as appropriate 

(see §§250.501 and 250.601 of this part for 

the definition of well-completion and 

well-workover operations). 

(b) Well-completion and wellworkover operations shall be conducted 

in a manner to protect against harm or 

damage to life (including fish and other 

aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not 

leased), the National security or defense, or the marine, coastal, or human 

environment. 

§ 250.1621 Crew instructions. 

Prior to engaging in well-completion 

or well-workover operations, crew 

members shall be instructed in the 

safety requirements of the operations 

to be performed, possible hazards to be 

encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and 

time of safety meetings shall be recorded and available for BSEE review. 

§ 250.1622 Approvals and reporting of 

well-completion and well-workover 

operations. 

(a) No well-completion or wellworkover operation shall begin until 

the lessee receives written approval 

from the District Manager. Approval 

for such operations shall be requested 

on Form BSEE–0124. Approvals by the 

District Manager shall be based upon a 

determination that the operations will 

be conducted in a manner to protect 


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§ 250.1623 30 CFR Ch. II (7–1–13 Edition) 

against harm or damage to life, property, natural resources of the OCS, including any mineral deposits, the National security or defense, or the marine, coastal, or human environment. 

(b) The following information shall 

be submitted with Form BSEE–0124 (or 

with Form BSEE–0123): 

(1) A brief description of the wellcompletion or well-workover procedures to be followed; 

(2) When changes in existing subsurface equipment are proposed, a schematic drawing showing the well equipment; and 

(3) Where the well is in zones known 

to contain H2S or zones where the presence of H2S is unknown, a description 

of the safety precautions to be implemented. 

(c)(1) Within 30 days after completion, Form BSEE–0125, including a 

schematic of the tubing and the results 

of any well tests, shall be submitted to 

the District Manager. 

(2) Within 30 days after completing 

the well-workover operation, except 

routine operations, Form BSEE–0124 

shall be submitted to the District Manager and shall include the results of 

any well tests and a new schematic of 

the well if any subsurface equipment 

has been changed. 

§ 250.1623 Well-control fluids, equipment, and operations. 

(a) Well-control fluids, equipment, 

and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The 

well shall be continuously monitored 

during well-completion and wellworkover operations and shall not be 

left unattended at any time unless the 

well is shut in and secured; 

(b) The following well-control fluid 

equipment shall be installed, maintained, and utilized: 

(1) A fill-up line above the uppermost 

BOP, 

(2) A well-control fluid-volume measuring device for determining fluid volumes when filling the hole on trips, 

and 

(3) A recording mud-pit-level indicator to determine mud-pit-volume 

gains and losses. This indicator shall 

include both a visual and an audible 

warning device. 

(c) When coming out of the hole with 

drill pipe or a workover string, the annulus shall be filled with well-control 

fluid before the change in fluid level 

decreases the hydrostatic pressure 75 

psi or every five stands of drill pipe or 

workover string, whichever gives a 

lower decrease in hydrostatic pressure. 

The number of stands of drill pipe or 

workover string and drill collars that 

may be pulled prior to filling the hole 

and the equivalent well-control fluid 

volume shall be calculated and posted 

near the operator’s station. A mechanical, volumetric, or electronic device 

for measuring the amount of well-control fluid required to fill the hole shall 

be utilized. 

§ 250.1624 Blowout prevention equipment. 

(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The 

working pressure of the BOP system 

and system components shall equal or 

exceed the expected surface pressure to 

which they may be subjected. 

(b) The minimum BOP stack for wellcompletion operations or for wellworkover operations with the tree removed shall consist of the following: 

(1) Three remote-controlled, hydraulically operated preventers including 

at least one equipped with pipe rams, 

one with blind rams, and one annular 

type. 

(2) When a tapered string is used, the 

minimum BOP stack shall consist of 

either of the following: 

(i) An annular preventer, one set of 

variable bore rams capable of sealing 

around both sizes in the string, and one 

set of blind rams; or 

(ii) An annular preventer, one set of 

pipe rams capable of sealing around the 

larger size string, a preventer equipped 

with blind-shear rams, and a crossover 

sub to the larger size pipe that shall be 

readily available on the rig floor. 

(c) The BOP systems for well-completion operations, or for well-workover 


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Safety & Environmental Enforcement, Interior § 250.1625 

operations with the tree removed, shall 

be equipped with the following: 

(1) An accumulator system that provides sufficient capacity to supply 1.5 

times the volume necessary to close 

and hold closed all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure without assistance from a charging system. 

After February 14, 1992, accumulator 

regulators supplied by rig air which do 

not have a secondary source of pneumatic supply shall be equipped with 

manual overrides or alternately other 

devices provided to ensure capability of 

hydraulic operations if rig air is lost; 

(2) An automatic backup to the accumulator system supplied by a power 

source independent from the power 

source to the primary accumulator system and possessing sufficient capacity 

to close all BOP’s and hold them 

closed; 

(3) Locking devices for the pipe-ram 

preventers; 

(4) At least one remote BOP-control 

station and one BOP-control station on 

the rig floor; and 

(5) A choke line and a kill line each 

equipped with two full-opening valves 

and a choke manifold. One of the 

choke-line valves and one of the killline valves shall be remotely controlled 

except that a check valve may be installed on the kill line in lieu of the remotely-controlled valve provided that 

two readily accessible manual valves 

are in place, and the check valve is 

placed between the manual valve and 

the pump. 

(d) The minimum BOP-stack components for well-workover operations 

with the tree in place and performed 

through the wellhead inside of the sulphur line using small diameter jointed 

pipe (usually 3⁄4 inch to 11⁄4 inch) as a 

work string; i.e., small-tubing operations, shall consist of the following: 

(1) For air line changes, the well 

shall be killed prior to beginning operations. The procedures for killing the 

well shall be included in the description of well-workover procedures in accordance with §250.1622 of this part. 

Under these circumstances, no BOP 

equipment is required. 

(2) For other work inside of the sulphur line, a tubing stripper or annular 

preventer shall be installed prior to beginning work. 

(e) An essentially full-opening, workstring safety valve shall be maintained 

on the rig floor at all times during 

well-completion operations. A wrench 

to fit the work-string safety valve shall 

be readily available. Proper connections shall be readily available for inserting a safety valve in the work 

string. 

§ 250.1625 Blowout preventer system 

testing, records, and drills. 

(a) Prior to conducting high-pressure 

tests, all BOP systems shall be tested 

to a pressure of 200 to 300 psi. 

(b) Ram-type BOP’s and the choke 

manifold shall be pressure tested with 

water to a rated working pressure or as 

otherwise approved by the District 

Manager. Annular type BOP’s shall be 

pressure tested with water to 70 percent of rated working pressure or as 

otherwise approved by the District 

Manager. 

(c) In conjunction with the weekly 

pressure test of BOP systems required 

in paragraph (d) of this section, the 

choke manifold valves, upper and lower 

kelly cocks, and drill-string safety 

valves shall be pressure tested to piperam test pressures. Safety valves with 

proper casing connections shall be actuated prior to running casing. 

(d) BOP system shall be pressure 

tested as follows: 

(1) When installed; 

(2) Before drilling out each string of 

casing or before continuing operations 

in cases where cement is not drilled 

out; 

(3) At least once each week, but not 

exceeding 7 days between pressure 

tests, alternating between control stations. If either control system is not 

functional, further drilling operations 

shall be suspended until that system 

becomes operable. A period of more 

than 7 days between BOP tests is allowed when there is a stuck drill pipe 

or there are pressure control operations, and remedial efforts are being 

performed, provided that the pressure 

tests are conducted as soon as possible 

and before normal operations resume. 

The time, date, and reason for postponing pressure testing shall be entered into the driller’s report. Pressure 


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§ 250.1626 30 CFR Ch. II (7–1–13 Edition) 

testing shall be performed at intervals 

to allow each drilling crew to operate 

the equipment. The weekly pressure 

test is not required for blind and blindshear rams; 

(4) Blind and blind-shear rams shall 

be actuated at least once every 7 days. 

Closing pressure on the blind and blindshear rams greater than necessary to 

indicate proper operation of the rams 

is not required; 

(5) Variable bore-pipe rams shall be 

pressure tested against all sizes of pipe 

in use, excluding drill collars and 

bottomhole tools; and 

(6) Following the disconnection or repair of any well-pressure containment 

seal in the wellhead/BOP stack assembly, the pressure tests may be limited 

to the affected component. 

(e) All personnel engaged in wellcompletion operations shall participate 

in a weekly BOP drill to familiarize 

crew members with appropriate safety 

measures. 

(f) The lessee shall record pressure 

conditions during BOP tests on pressure charts, unless otherwise approved 

by the District Manager. The test duration for each BOP component tested 

shall be sufficient to demonstrate that 

the component is effectively holding 

pressure. The charts shall be certified 

as correct by the operator’s representative at the facility. 

(g) The time, date, and results of all 

pressure tests, actuations, inspections, 

and crew drills of the BOP system and 

system components shall be recorded 

in the operations log. The BOP tests 

shall be documented in accordance 

with the following: 

(1) The documentation shall indicate 

the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an 

alternate, the documentation in the 

operations log may reference a BOP 

test plan that contains the required information and is retained on file at the 

facility. 

(2) The control station used during 

the test shall be identified in the operations log. 

(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to 

remedy such problems or irregularities 

shall be noted in the operations log. 

(4) Documentation required to be entered in the driller’s report may instead be referenced in the driller’s report. All records, including pressure 

charts, driller’s report, and referenced 

documents, pertaining to BOP tests, 

actuations, and inspections shall be 

available for BSEE review at the facility for the duration of the drilling activity. Following completion of the 

drilling activity, all drilling records 

shall be retained for a period of 2 years 

at the facility, at the lessee’s field office nearest the OCS facility, or at another location conveniently available 

to the District Manager. 

§ 250.1626 Tubing and wellhead equipment. 

(a) No tubing string shall be placed 

into service or continue to be used unless such tubing string has the necessary strength and pressure integrity 

and is otherwise suitable for its intended use. 

(b) Wellhead, tree, and related equipment shall be designed, installed, tested, used, and maintained so as to 

achieve and maintain pressure control. 

§ 250.1627 Production requirements. 

(a) The lessee shall conduct sulphur 

production operations in compliance 

with the approved Development and 

Production Plan requirements of 

§§250.1627 through 250.1634 of this subpart and requirements of this part, as 

appropriate. 

(b) Production safety equipment 

shall be designed, installed, used, 

maintained, and tested in a manner to 

assure the safety of operations and protection of the human, marine, and 

coastal environments. 

§ 250.1628 Design, installation, and operation of production systems. 

(a) General. All production facilities 

shall be designed, installed, and maintained in a manner that provides for efficiency and safety of operations and 

protection of the environment. 

(b) Approval of design and installation 

features for sulphur production facilities. 

Prior to installation, the lessee shall 

submit a sulphur production system 


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Safety & Environmental Enforcement, Interior § 250.1628 

application, in duplicate, to the District Manager for approval. The application shall include information relative to the proposed design and installation features. Information concerning approved design and installation features shall be maintained by 

the lessee at the lessee’s offshore field 

office nearest the OCS facility or at another location conveniently available 

to the District Manager. All approvals 

are subject to field verification. The 

application shall include the following: 

(1) A schematic flow diagram showing size, capacity, design, working 

pressure of separators, storage tanks, 

compressor pumps, metering devices, 

and other sulphur-handling vessels; 

(2) A schematic piping diagram showing the size and maximum allowable 

working pressures as determined in accordance with API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems (as incorporated 

by reference in §250.198); 

(3) Electrical system information including a plan of each platform deck, 

outlining all hazardous areas classified 

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, or 

API RP 505, Recommended Practice for 

Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, 

Zone 1, and Zone 2 (as incorporated by 

reference in §250.198), and outlining 

areas in which potential ignition 

sources are to be installed; 

(4) Certification that the design for 

the mechanical and electrical systems 

to be installed were approved by registered professional engineers. After 

these systems are installed, the lessee 

shall submit a statement to the District Manager certifying that the new 

installations conform to the approved 

designs of this subpart. 

(c) Hydrocarbon handling vessels associated with fuel gas system. You must 

protect hydrocarbon handling vessels 

associated with the fuel gas system 

with a basic and ancillary surface safety system. This system must be designed, analyzed, installed, tested, and 

maintained in operating condition in 

accordance with API RP 14C, Analysis, 

Design, Installation, and Testing of 

Basic Surface Safety Systems for Offshore Production Platforms (as incorporated by reference in §250.198). If 

processing components are to be utilized, other than those for which Safety Analysis Checklists are included in 

API RP 14C, you must use the analysis 

technique and documentation specified 

therein to determine the effect and requirements of these components upon 

the safety system. 

(d) Approval of safety-systems design 

and installation features for fuel gas system. Prior to installation, the lessee 

shall submit a fuel gas safety system 

application, in duplicate, to the District Manager for approval. The application shall include information relative to the proposed design and installation features. Information concerning approved design and installation features shall be maintained by 

the lessee at the lessee’s offshore field 

office nearest the OCS facility or at another location conveniently available 

to the District Manager. All approvals 

are subject to field verification. The 

application shall include the following: 

(1) A schematic flow diagram showing size, capacity, design, working 

pressure of separators, storage tanks, 

compressor pumps, metering devices, 

and other hydrocarbon-handling vessels; 

(2) A schematic flow diagram (API 

RP 14C, Figure E1, as incorporated by 

reference in §250.198) and the related 

Safety Analysis Function Evaluation 

chart (API RP 14C, subsection 4.3c, as 

incorporated by reference in §250.198). 

(3) A schematic piping diagram showing the size and maximum allowable 

working pressures as determined in accordance with API RP 14E, Design and 

Installation of Offshore Production 

Platform Piping Systems (as incorporated by reference in §250.198); 

(4) Electrical system information including the following: 

(i) A plan of each platform deck, outlining all hazardous areas classified 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, or API RP 


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§ 250.1629 30 CFR Ch. II (7–1–13 Edition) 

505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities 

Classified as Class I, Zone 0, Zone 1, 

and Zone 2 (as incorporated by reference in §250.198), and outlining areas 

in which potential ignition sources are 

to be installed; 

(ii) All significant hydrocarbon 

sources and a description of the type of 

decking, ceiling, walls (e.g., grating or 

solid), and firewalls; and 

(iii) Elementary electrical schematic 

of any platform safety shutdown system with a functional legend. 

(5) Certification that the design for 

the mechanical and electrical systems 

to be installed was approved by registered professional engineers. After 

these systems are installed, the lessee 

shall submit a statement to the District Manager certifying that the new 

installations conform to the approved 

designs of this subpart; and 

(6) Design and schematics of the installation and maintenance of all fireand gas-detection systems including 

the following: 

(i) Type, location, and number of detection heads; 

(ii) Type and kind of alarm, including 

emergency equipment to be activated; 

(iii) Method used for detection; 

(iv) Method and frequency of calibration; and 

(v) A functional block diagram of the 

detection system, including the electric power supply. 

§ 250.1629 Additional production and 

fuel gas system requirements. 

(a) General. Lessees shall comply 

with the following production safety 

system requirements (some of which 

are in addition to those contained in 

§250.1628 of this part). 

(b) Design, installation, and operation 

of additional production systems, including fuel gas handling safety systems. (1) 

Pressure and fired vessels must be designed, fabricated, and code stamped in 

accordance with the applicable provisions of sections I, IV, and VIII of the 

American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (as specified in §250.198). Pressure and fired vessels must have maintenance inspection, rating, repair, and 

alteration performed in accordance 

with the applicable provisions of API 

Pressure Vessel Inspections Code: InService Inspection, Rating, Repair, and 

Alteration, API 510 (except Sections 5.8 

and 9.5) (as incorporated by reference 

in §250.198). 

(i) Pressure safety relief valves shall 

be designed, installed, and maintained 

in accordance with applicable provisions of sections I, IV, and VIII of the 

ANSI/ASME Boiler and Pressure Vessel 

Code (as specified in §250.198). The safety relief valves shall conform to the 

valve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valves 

shall be set no higher than the maximum-allowable working pressure of 

the vessel. All safety relief valves and 

vents shall be piped in such a way as to 

prevent fluid from striking personnel 

or ignition sources. 

(ii) The lessee shall use pressure recorders to establish the operating pressure ranges of pressure vessels in order 

to establish the pressure-sensor settings. Pressure-recording charts used 

to determine operating pressure ranges 

shall be maintained by the lessee for a 

period of 2 years at the lessee’s field office nearest the OCS facility or at another location conveniently available 

to the District Manager. The high-pressure sensor shall be set no higher than 

15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall 

also be set sufficiently below (15 percent or 5 psi, whichever is greater) the 

safety relief valve’s set pressure to assure that the high-pressure sensor 

sounds an alarm before the safety relief 

valve starts relieving. The low-pressure 

sensor shall sound an alarm no lower 

than 15 percent or 5 psi, whichever is 

greater, below the lowest pressure in 

the operating range. 

(2) Engine exhaust. You must equip 

engine exhausts to comply with the insulation and personnel protection requirements of API RP 14C, section 

4.2c(4) (as incorporated by reference in 

§250.198). Exhaust piping from diesel 

engines must be equipped with spark 

arresters. 

(3) Firefighting systems. Firefighting 

systems must conform to subsection 

5.2, Fire Water Systems, of API RP 

14G, Recommended Practice for Fire 


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Safety & Environmental Enforcement, Interior § 250.1630 

Prevention and Control on Open Type 

Offshore Production Platforms (as incorporated by reference in §250.198), 

and must be subject to the approval of 

the District Manager. Additional requirements must apply as follows: 

(i) A firewater system consisting of 

rigid pipe with firehose stations shall 

be installed. The firewater system shall 

be installed to provide needed protection, especially in areas where fuel 

handling equipment is located. 

(ii) Fuel or power for firewater pump 

drivers shall be available for at least 30 

minutes of run time during platform 

shut-in time. If necessary, an alternate 

fuel or power supply shall be installed 

to provide for this pump-operating 

time unless an alternate firefighting 

system has been approved by the District Manager; 

(iii) A firefighting system using 

chemicals may be used in lieu of a 

water system if the District Manager 

determines that the use of a chemical 

system provides equivalent fire-protection control; and 

(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a 

prominent place on the facility or 

structure. 

(4) Fire- and gas-detection system. (i) 

Fire (flame, heat, or smoke) sensors 

shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated, 

enclosed classified areas. Adequate 

ventilation is defined as ventilation 

that is sufficient to prevent accumulation of significant quantities of vaporair mixture in concentrations over 25 

percent of the lower explosive limit. 

One approved method of providing adequate ventilation is a change of air volume each 5 minutes or 1 cubic foot of 

air-volume flow per minute per square 

foot of solid floor area, whichever is 

greater. Enclosed areas (e.g., buildings, 

living quarters, or doghouses) are defined as those areas confined on more 

than four of their six possible sides by 

walls, floors, or ceilings more restrictive to air flow than grating or fixed 

open louvers and of sufficient size to 

allow entry of personnel. A classified 

area is any area classified Class I, 

Group D, Division 1 or 2, following the 

guidelines of API RP 500 (as incorporated by reference in §250.198), or any 

area classified Class I, Zone 0, Zone 1, 

or Zone 2, following the guidelines of 

API RP 505 (as incorporated by reference in §205.198). 

(ii) All detection systems shall be capable of continuous monitoring. Firedetection systems and portions of combustible gas-detection systems related 

to the higher gas concentration levels 

shall be of the manual-reset type. Combustible gas-detection systems related 

to the lower gas-concentration level 

may be of the automatic-reset type. 

(iii) A fuel-gas odorant or an automatic gas-detection and alarm system 

is required in enclosed, continuously 

manned areas of the facility that are 

provided with fuel gas. Living quarters 

and doghouses not containing a gas 

source and not located in a classified 

area do not require a gas detection system. 

(iv) The District Manager may require the installation and maintenance 

of a gas detector or alarm in any potentially hazardous area. 

(v) Fire- and gas-detection systems 

must be an approved type, designed and 

installed according to API RP 14C, API 

RP 14G, and either API RP 14F or API 

RP 14FZ (the preceding four documents 

as incorporated by reference in 

§250.198). 

(c) General platform operations. Safety 

devices shall not be bypassed or 

blocked out of service unless they are 

temporarily out of service for startup, 

maintenance, or testing procedures. 

Only the minimum number of safety 

devices shall be taken out of service. 

Personnel shall monitor the bypassed 

or blocked out functions until the safety devices are placed back in service. 

Any safety device that is temporarily 

out of service shall be flagged by the 

person taking such device out of service. 

§ 250.1630 Safety-system testing and 

records. 

(a) Inspection and testing. You must 

inspect and successfully test safety 

system devices at the interval specified 

below or more frequently if operating 

conditions warrant. Testing must be in 

accordance with API RP 14C, Appendix 

D (as incorporated by reference in 

§250.198). For safety system devices 


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§ 250.1631 30 CFR Ch. II (7–1–13 Edition) 

other than those listed in API RP 14C, 

Appendix D, you must utilize the analysis technique and documentation 

specified therein for inspection and 

testing of these components, and the 

following: 

(1) Safety relief valves on the natural 

gas feed system for power plant operations such as pressure safety valves 

shall be inspected and tested for operation at least once every 12 months. 

These valves shall be either bench tested or equipped to permit testing with 

an external pressure source. 

(2) The following safety devices (excluding electronic pressure transmitters and level sensors) must be inspected and tested at least once each 

calendar month, but at no time may 

more than 6 weeks elapse between 

tests: 

(i) All pressure safety high or pressure safety low, and 

(ii) All level safety high and level 

safety low controls. 

(3) The following electronic pressure 

transmitters and level sensors must be 

inspected and tested at least once 

every 3 months, but at no time may 

more than 120 days elapse between 

tests: 

(i) All PSH or PSL, and 

(ii) All LSH and LSL controls. 

(4) All pumps for firewater systems 

shall be inspected and operated weekly. 

(5) All fire- (flame, heat, or smoke) 

and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided 

that testing can be performed in a nondestructive manner. 

(6) Prior to the commencement of 

production, the lessee shall notify the 

District Manager when the lessee is 

ready to conduct a preproduction test 

and inspection of the safety system. 

The lessee shall also notify the District 

Manager upon commencement of production in order that a complete inspection may be conducted. 

(b) Records. The lessee shall maintain 

records for a period of 2 years for each 

safety device installed. These records 

shall be maintained by the lessee at 

the lessee’s field office nearest the OCS 

facility or another location conveniently available to the District Manager. These records shall be available 

for BSEE review. The records shall 

show the present status and history of 

each safety device, including dates and 

details of installation, removal, inspection, testing, repairing, adjustments, 

and reinstallation. 

§ 250.1631 Safety device training. 

Prior to engaging in production operations on a lease and periodically 

thereafter, personnel installing, inspecting, testing, and maintaining 

safety devices shall be instructed in 

the safety requirements of the operations to be performed; possible hazards to be encountered; and general 

safety considerations to be taken to 

protect personnel, equipment, and the 

environment. Date and time of safety 

meetings shall be recorded and available for BSEE review. 

§ 250.1632 Production rates. 

Each sulphur deposit shall be produced at rates that will provide economic development and depletion of 

the deposit in a manner that would 

maximize the ultimate recovery of sulphur without resulting in waste (e.g., 

an undue reduction in the recovery of 

oil and gas from an associated hydrocarbon accumulation). 

§ 250.1633 Production measurement. 

(a) General. Measurement equipment 

and security procedures shall be designed, installed, used, maintained, and 

tested so as to accurately and completely measure the sulphur produced 

on a lease for purposes of royalty determination. 

(b) Application and approval. The lessee shall not commence production of 

sulphur until the Regional Supervisor 

has approved the method of measurement. The request for approval of the 

method of measurement shall contain 

sufficient information to demonstrate 

to the satisfaction of the Regional Supervisor that the method of measurement meets the requirements of paragraph (a) of this section. 

§ 250.1634 Site security. 

(a) All locations where sulphur is 

produced, measured, or stored shall be 

operated and maintained to ensure 

against the loss or theft of produced 

sulphur and to assure accurate and 


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Safety & Environmental Enforcement, Interior § 250.1703 

complete measurement of produced 

sulphur for royalty purposes. 

(b) Evidence of mishandling of produced sulphur from an offshore lease, 

or tampering or falsifying any measurement of production for an offshore 

lease, shall be reported to the Regional 

Supervisor as soon as possible but no 

later than the next business day after 

discovery of the evidence of mishandling. 

Subpart Q—Decommissioning 

Activities 

GENERAL

§ 250.1700 What do the terms ‘‘decommissioning’’, ‘‘obstructions’’, and 

‘‘facility’’ mean? 

(a) Decommissioning means: 

(1) Ending oil, gas, or sulphur operations; and 

(2) Returning the lease or pipeline 

right-of-way to a condition that meets 

the requirements of regulations of 

BSEE and other agencies that have jurisdiction over decommissioning activities. 

(b) Obstructions mean structures, 

equipment, or objects that were used in 

oil, gas, or sulphur operations or marine growth that, if left in place, would 

hinder other users of the OCS. Obstructions may include, but are not limited 

to, shell mounds, wellheads, casing 

stubs, mud line suspensions, well protection devices, subsea trees, jumper 

assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and 

power cables. 

(c) Facility means any installation 

other than a pipeline used for oil, gas, 

or sulphur activities that is permanently or temporarily attached to the 

seabed on the OCS. Facilities include 

production and pipeline risers, templates, pilings, and any other facility 

or equipment that constitutes an obstruction such as jumper assemblies, 

termination skids, umbilicals, anchors, 

and mooring lines. 

§ 250.1701 Who must meet the decommissioning obligations in this subpart? 

(a) Lessees and owners of operating 

rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to 

lease-term pipelines, as the obligations 

accrue and until each obligation is 

met. 

(b) All holders of a right-of-way are 

jointly and severally liable for meeting 

decommissioning obligations for facilities on their right-of-way, including 

right-of-way pipelines, as the obligations accrue and until each obligation 

is met. 

(c) In this subpart, the terms ‘‘you’’ 

or ‘‘I’’ refer to lessees and owners of operating rights, as to facilities installed 

under the authority of a lease, and to 

right-of-way holders as to facilities installed under the authority of a rightof-way. 

§ 250.1702 When do I accrue decommissioning obligations? 

You accrue decommissioning obligations when you do any of the following: 

(a) Drill a well; 

(b) Install a platform, pipeline, or 

other facility; 

(c) Create an obstruction to other 

users of the OCS; 

(d) Are or become a lessee or the 

owner of operating rights of a lease on 

which there is a well that has not been 

permanently plugged according to this 

subpart, a platform, a lease term pipeline, or other facility, or an obstruction; 

(e) Are or become the holder of a 

pipeline right-of-way on which there is 

a pipeline, platform, or other facility, 

or an obstruction; or 

(f) Re-enter a well that was previously plugged according to this subpart. 

§ 250.1703 What are the general requirements for decommissioning? 

When your facilities are no longer 

useful for operations, you must: 

(a) Get approval from the appropriate 

District Manager before decommissioning wells and from the Regional 

Supervisor before decommissioning 


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§ 250.1704 30 CFR Ch. II (7–1–13 Edition) 

platforms and pipelines or other facilities; 

(b) Permanently plug all wells; 

(c) Remove all platforms and other 

facilities, except as provided in 

§§250.1725(a) and 250.1730. 

(d) Decommission all pipelines; 

(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and 

(f) Conduct all decommissioning activities in a manner that is safe, does 

not unreasonably interfere with other 

uses of the OCS, and does not cause 

undue or serious harm or damage to 

the human, marine, or coastal environment. 

§ 250.1704 When must I submit decommissioning applications and reports? 

You must submit decommissioning 

applications and receive approval and 

submit subsequent reports according to 

the table in this section. 

DECOMMISSIONING APPLICATIONS AND REPORTS TABLE

Decommissioning applications and reports When to submit Instructions 

(a) Initial platform removal application 

[not required in the Gulf of Mexico 

OCS Region].

In the Pacific OCS Region or Alaska 

OCS Region, submit the application 

to the Regional Supervisor at least 

2 years before production is projected to cease.

Include information required under 

§ 250.1726. 

(b) Final removal application for a platform or other facility.Before removing a platform or other 

facility in the Gulf of Mexico OCS 

Region, or not more than 2 years 

after the submittal of an initial platform removal application to the Pacific OCS Region and the Alaska 

OCS Region.

Include information required under 

§ 250.1727. 

(c) Post-removal report for a platform 

or other facility.

Within 30 days after you remove a 

platform or other facility.

Include information required under 

§ 250.1729. 

(d) Pipeline decommissioning application.Before you decommission a pipeline .. Include information required under 

§ 250.1751(a) or § 250.1752(a), as applicable. 

(e) Post-pipeline decommissioning report.Within 30 days after you decommission a pipeline.Include information required under 

§ 250.1753. 

(f) Site clearance report for a platform 

or other facility.

Within 30 days after you complete site 

clearance verification activities.

Include information required under 

§ 250.1743(b). 

(g) Form BSEE–0124, Application for 

Permit to Modify (APM). The submission of your APM must be accompanied by payment of the service fee 

listed in § 250.125.

(1) Before you temporarily abandon or 

permanently plug a well or zone.

(i) Include information required under 

§§ 250.1712 and 250.1721. 

(ii) When using a BOP for abandonment operations include information required under 

§ 250.1705. 

(2) Within 30 days after you plug a 

well.

Include information required under 

§ 250.1717. 

(3) Before you install a subsea protective device.Refer to § 250.1722(a). 

(4) Within 30 days after you complete 

a protective device trawl test.

Include information required under 

§ 250.1722(d). 

(5) Before you remove any casing 

stub or mud line suspension equipment and any subsea protective device.

Refer to § 250.1723. 

(6) Within 30 days after you complete 

site clearance verification activities.

Include information required under 

§ 250.1743(a). 

[76 FR 64462, Oct. 18, 2011, as amended at 77 FR 50896, Aug. 22, 2012] 

§ 250.1705 What BOP information must 

I submit? 

If you plan to use a BOP for abandonment operations, your decommissioning application must include the 

following BOP descriptions: 

(a) A description of the BOP system 

and system components, including 

pressure ratings of BOP equipment and 

proposed BOP test pressures; 

(b) A schematic drawing of the BOP 

system that shows the inside diameter 

of the BOP stack, number and type of 

preventers, all control systems and 


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Safety & Environmental Enforcement, Interior § 250.1706 

pods, location of choke and kill lines, 

and associated valves; 

(c) Independent third-party 

verification and supporting documentation that show the blind-shear 

rams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole 

under maximum anticipated surface 

pressure. The documentation must include actual shearing and subsequent 

pressure integrity test results for the 

most rigid pipe to be used and calculations of shearing capacity of all pipe to 

be used in the well, including correction for Maximum Anticipated Surface 

Pressure (MASP); 

(d) When you use a subsea BOP stack, 

independent third-party verification 

that shows: 

(1) The BOP stack is designed for the 

specific equipment on the rig and for 

the specific well design; 

(2) The BOP stack has not been compromised or damaged from previous 

service; 

(3) The BOP stack will operate in the 

conditions in which it will be used; and 

(e) The qualifications of the independent third-party referenced in paragraphs (c) and (d) of this section including evidence that: 

(1) The independent third-party in 

this section is a technical classification society, or a licensed professional 

engineering firm, or a registered professional engineer capable of providing 

the verifications required under this 

part. 

(2) You must: 

(i) Include evidence that the registered professional engineer, or a technical classification society, or engineering firm you are using or its employees hold appropriate licenses to 

perform the verification in the appropriate jurisdiction, and evidence to 

demonstrate that the individual, society, or firm has the expertise and experience necessary to perform the required verifications. 

(ii) Ensure that an official representative of BSEE will have access to the 

location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearing 

ram tests or inspections, you must notify the BSEE District Manager at 

least 72 hours in advance. 

[77 FR 50897, Aug. 22, 2012] 

§ 250.1706 What are the requirements 

for blowout prevention equipment? 

If you use a BOP for any well abandonment operations, your BOP must 

meet the following requirements: 

(a) The BOP system, system components, and related well-control equipment must be designed, used, maintained, and tested in a manner necessary to assure well-control in foreseeable conditions and circumstances, 

including subfreezing conditions. The 

working pressure rating of the BOP 

system and system components must 

exceed the expected surface pressure to 

which they may be subjected. If the expected surface pressure exceeds the 

rated working pressure of the annular 

preventer, you must submit with Form 

BSEE–0124, requesting approval of the 

well abandonment operations, a wellcontrol procedure that indicates how 

the annular preventer will be utilized, 

and the pressure limitations that will 

be applied during each mode of pressure control. 

(b) The minimum BOP system for 

well abandonment operations with the 

tree removed must meet the appropriate standards from the following 

table: 

When . . . The minimum BOP stack must include . . . 

(1) The expected pressure is less than 

5,000 psi, 

Three BOPs consisting of an annular, one set of pipe rams, and one set of blindshear rams. 

(2) The expected pressure is 5,000 psi or 

greater or you use multiple tubing 

strings, 

Four BOPs consisting of an annular, two sets of pipe rams, and one set of blindshear rams. 

(3) You handle multiple tubing strings simultaneously, Four BOPs consisting of an annular, one set of pipe rams, one set of dual pipe 

rams, and one set of blind-shear rams. 

(4) You use a tapered drill string, (i) At least one set of pipe rams that are capable of sealing around each size of 

drill string. 

(ii) If the expected pressure is greater than 5,000 psi, then you must have at least 

two sets of pipe rams that are capable of sealing around the larger size drill 

string. 

(iii) You may substitute one set of variable bore rams for two sets of pipe rams. 


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§ 250.1706 30 CFR Ch. II (7–1–13 Edition) 

When . . . The minimum BOP stack must include . . . 

(5) You use a subsea BOP stack, The requirements in § 250.442(a) of this part. 

(c) The BOP systems for well abandonment operations with the tree removed must be equipped with the following: 

(1) A hydraulic-actuating system 

that provides sufficient accumulator 

capacity to supply 1.5 times the volume 

necessary to close all BOP equipment 

units with a minimum pressure of 200 

psi above the precharge pressure without assistance from a charging system. 

Accumulator regulators supplied by rig 

air and without a secondary source of 

pneumatic supply, must be equipped 

with manual overrides, or alternately, 

other devices provided to ensure capability of hydraulic operations if rig air 

is lost; 

(2) A secondary power source, independent from the primary power 

source, with sufficient capacity to 

close all BOP system components and 

hold them closed; 

(3) Locking devices for the pipe-ram 

preventers; 

(4) At least one remote BOP-control 

station and one BOP-control station on 

the rig floor; and 

(5) A choke line and a kill line each 

equipped with two full opening valves 

and a choke manifold. At least one of 

the valves on the choke-line must be 

remotely controlled. At least one of 

the valves on the kill line must be remotely controlled, except that a check 

valve on the kill line in lieu of the remotely controlled valve may be installed, provided two readily accessible 

manual valves are in place and the 

check valve is placed between the manual valves and the pump. This equipment must have a pressure rating at 

least equivalent to the ram preventers. 

You must install the choke line above 

the bottom ram and may install the 

kill line below the bottom ram. 

(d) The minimum BOP system components for well abandonment operations with the tree in place and performed through the wellhead inside of 

conventional tubing using small-diameter jointed pipe (usually 3⁄4 inch to 

11⁄4 inch) as a work string, i.e., smalltubing operations, must include the 

following: 

(1) Two sets of pipe rams, and 

(2) One set of blind rams. 

(e) The subsea BOP system for well 

abandonment operations must meet 

the requirements in §250.442 of this 

part. 

(f) For coiled tubing operations with 

the production tree in place, you must 

meet the following minimum requirements for the BOP system: 

(1) BOP system components must be 

in the following order from the top 

down: 

BOP system when expected 

surface pressures are less than 

or equal to 3,500 psi 

BOP system when expected 

surface pressures are greater 

than 3,500 psi 

BOP system for wells with returns taken through an outlet on 

the BOP stack 

(i) Stripper or annular-type 

well-control component, 

Stripper or annular-type wellcontrol component, Stripper or annular-type well-control component. 

(ii) Hydraulically-operated blind 

rams, 

Hydraulically-operated blind 

rams,.

Hydraulically-operated blind rams. 

(iii) Hydraulically-operated 

shear rams, 

Hydraulically-operated shear 

rams,.

Hydraulically-operated shear rams. 

(iv) Kill line inlet, Kill line inlet, Kill line inlet. 

(v) Hydraulically-operated twoway slip rams, Hydraulically-operated twoway slip rams, Hydraulically-operated two-way slip rams. 

Hydraulically-operated pipe rams. 

(vi) Hydraulically-operated pipe 

rams, 

Hydraulically-operated pipe 

rams. 

Hydraulically-operated blindshear rams. These rams 

should be located as close 

to the tree as practical, 

A flow tee or cross. 

Hydraulically-operated pipe rams. 

Hydraulically-operated blind-shear rams on wells with surface 

pressures >3,500 psi. As an option, the pipe rams can be 

placed below the blind-shear rams. The blind-shear rams 

should be located as close to the tree as practical. 


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Safety & Environmental Enforcement, Interior § 250.1707 

(2) You may use a set of hydraulically-operated combination rams for 

the blind rams and shear rams. 

(3) You may use a set of hydraulically-operated combination rams for 

the hydraulic two-way slip rams and 

the hydraulically-operated pipe rams. 

(4) You must attach a dual check 

valve assembly to the coiled tubing 

connector at the downhole end of the 

coiled tubing string for all coiled tubing well abandonment operations. If 

you plan to conduct operations without 

downhole check valves, you must describe alternate procedures and equipment in Form BSEE–0124, Application 

for Permit to Modify, and have it approved by the BSEE District Manager. 

(5) You must have a kill line and a 

separate choke line. You must equip 

each line with two full-opening valves 

and at least one of the valves must be 

remotely controlled. You may use a 

manual valve instead of the remotely 

controlled valve on the kill line if you 

install a check valve between the two 

full-opening manual valves and the 

pump or manifold. The valves must 

have a working pressure rating equal 

to or greater than the working pressure rating of the connection to which 

they are attached, and you must install them between the well-control 

stack and the choke or kill line. For 

operations with expected surface pressures greater than 3,500 psi, the kill 

line must be connected to a pump or 

manifold. You must not use the kill 

line inlet on the BOP stack for taking 

fluid returns from the wellbore. 

(6) You must have a hydraulic-actuating system that provides sufficient 

accumulator capacity to close-openclose each component in the BOP 

stack. This cycle must be completed 

with at least 200 psi above the precharge pressure, without assistance 

from a charging system. 

(7) All connections used in the surface BOP system from the tree to the 

uppermost required ram must be 

flanged, including the connections between the well-control stack and the 

first full-opening valve on the choke 

line and the kill line. 

(g) The minimum BOP system components for well abandonment operations with the tree in place and performed by moving tubing or drill pipe 

in or out of a well under pressure utilizing equipment specifically designed 

for that purpose, i.e., snubbing operations, must include the following: 

(1) One set of pipe rams hydraulically 

operated, and 

(2) Two sets of stripper-type pipe 

rams hydraulically operated with spacer spool. 

(h) An inside BOP or a spring-loaded, 

back-pressure safety valve, and an essentially full-opening, work-string 

safety valve in the open position must 

be maintained on the rig floor at all 

times during well abandonment operations when the tree is removed or during well abandonment operations with 

the tree installed and using small tubing as the work string. A wrench to fit 

the work-string safety valve must be 

readily available. Proper connections 

must be readily available for inserting 

valves in the work string. The fullopening safety valve is not required for 

coiled tubing or snubbing operations. 

[77 FR 50897, Aug. 22, 2012] 

§ 250.1707 What are the requirements 

for blowout preventer system testing, records, and drills? 

(a) BOP pressure tests. When you pressure test the BOP system, you must 

conduct a low-pressure test and a highpressure test for each component. You 

must conduct the low-pressure test before the high-pressure test. For purposes of this section, BOP system components include ram-type BOP’s, related control equipment, choke and 

kill lines, and valves, manifolds, strippers, and safety valves. Surface BOP 

systems must be pressure tested with 

water. 

(1) Low pressure tests. You must successfully test all BOP system components to a low pressure between 200 and 

300 psi. Any initial pressure equal to or 

greater than 300 psi must be bled back 

to a pressure between 200 and 300 psi 

before starting the test. If the initial 

pressure exceeds 500 psi, you must 

bleed back to zero before starting the 

test. 

(2) High pressure tests. You must successfully test all BOP system components to the rated working pressure of 

the BOP equipment, or as otherwise approved by the BSEE District Manager. 


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§ 250.1707 30 CFR Ch. II (7–1–13 Edition) 

You must successfully test the annular-type BOP at 70 percent of its rated 

working pressure or as otherwise approved by the BSEE District Manager. 

(3) Other testing requirements. You 

must test variable bore pipe rams 

against the largest and smallest sizes 

of tubulars in use (jointed pipe, seamless pipe) in the well. 

(b) You must test the BOP systems at 

the following times: 

(1) When installed; 

(2) At least every 7 days, alternating 

between control stations and at staggered intervals to allow each crew to 

operate the equipment. If either control system is not functional, further 

operations must be suspended until the 

nonfunctional system is operable. The 

test every 7 days is not required for 

blind or blind-shear rams. The blind or 

blind-shear rams must be tested at 

least once every 30 days during operation. A longer period between blowout 

preventer tests is allowed when there is 

a stuck pipe or pressure-control operation and remedial efforts are being 

performed. The tests must be conducted as soon as possible and before 

normal operations resume. The reason 

for postponing testing must be entered 

into the operations log. The BSEE District Manager may require alternate 

test frequencies if conditions or BOP 

performance warrant. 

(3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure tested. 

(c) All personnel engaged in well 

abandonment operations must participate in a weekly BOP drill to familiarize crew members with appropriate 

safety measures. 

(d) You may conduct a stump test for 

the BOP system on location. A plan describing the stump test procedures 

must be included in your Application 

for Permit to Modify, Form BSEE–0124, 

and must be approved by the BSEE 

District Manager. 

(e) You must test the coiled tubing 

connector to a low pressure of 200 to 300 

psi, followed by a high pressure test to 

the rated working pressure of the connector or the expected surface pressure, whichever is less. You must successfully pressure test the dual check 

valves to the rated working pressure of 

the connector, the rated working pressure of the dual check valve, expected 

surface pressure, or the collapse pressure of the coiled tubing, whichever is 

less. 

(f) You must record test pressures 

during BOP and coiled tubing tests on 

a pressure chart, or with a digital recorder, unless otherwise approved by 

the BSEE District Manager. The test 

interval for each BOP system component must be 5 minutes, except for 

coiled tubing operations, which must 

include a 10 minute high-pressure test 

for the coiled tubing string. Your representative at the facility must certify 

that the charts are correct. 

(g) The time, date, and results of all 

pressure tests, actuations, inspections, 

and crew drills of the BOP system, system components, and marine risers 

must be recorded in the operations log. 

The BOP tests must be documented in 

accordance with the following: 

(1) The documentation must indicate 

the sequential order of BOP and auxiliary equipment testing, the pressure, 

and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test 

plan that contains the required information and is retained on file at the facility. 

(2) The control station used during 

the test must be identified in the operations log. For a subsea system, the 

pod used during the test must be identified in the operations log. 

(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to 

remedy such problems or irregularities, 

must be noted in the operations log. 

(4) Documentation required to be entered in the operations log may instead 

be referenced in the operations log. 

You must make all records including 

pressure charts, operations log, and 

referenced documents pertaining to 

BOP tests, actuations, and inspections, 

available for BSEE review at the facility for the duration of well abandonment activity. Following completion of 

the well abandonment activity, you 

must retain all such records for a period of two years at the facility, at the 


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Safety & Environmental Enforcement, Interior § 250.1708 

lessee’s field office nearest the OCS facility, or at another location conveniently available to the BSEE District 

Manager. 

(h) Stump test a subsea BOP system 

before installation. You must use 

water to conduct this test. You may 

use drilling fluids to conduct subsequent tests of a subsea BOP system. 

You must stump test the subsea BOP 

within 30 days of the initial test on the 

seafloor. You must: 

(1) Test all ROV intervention functions on your subsea BOP stack during 

the stump test. Each ROV must be 

fully compatible with the BOP stack 

ROV intervention panels. You must 

also test and verify closure of at least 

one set of rams during the initial test 

on the seafloor. You must submit test 

procedures, including how you will test 

each ROV function, with your APM for 

BSEE District Manager approval. You 

must: 

(i) Ensure that the ROV hot stabs are 

function tested and are capable of actuating, at a minimum, one set of pipe 

rams and one set of blind-shear rams 

and unlatching the LMRP; 

(ii) Document all your test results 

and make them available to BSEE 

upon request; and 

(2) Function test autoshear and 

deadman systems on your subsea BOP 

stack during the stump test. You must 

also test the deadman system and 

verify closure of at least one set of 

blind-shear rams during the initial test 

on the seafloor. When you conduct the 

initial deadman system test on the 

seafloor you must ensure the well is secure and, if hydrocarbons have been 

present, appropriate barriers are in 

place to isolate hydrocarbons from the 

wellhead. You must also have an ROV 

on bottom during the test. You must: 

(i) Submit test procedures with your 

APM for BSEE District Manager approval. The procedures for these function tests must include documentation 

of the controls and circuitry of the system utilized during each test. The procedure must also describe how the ROV 

will be utilized during this operation. 

(ii) Document the results of each test 

and make them available to BSEE 

upon request. 

[77 FR 50899, Aug. 22, 2012] 

§ 250.1708 What are my BOP inspection and maintenance requirements? 

(a) BOP inspections. (1) You must inspect your BOP system to ensure that 

the equipment functions properly. The 

BOP inspections must meet or exceed 

the provisions of Sections 17.10 and 

18.10, Inspections, described in API RP 

53, Recommended Practices for Blowout Prevention Equipment Systems for 

Drilling Wells (incorporated by reference as specified in §250.198). You 

must document how you met or exceeded the provisions of Sections 17.10 and 

18.10 described in API RP 53, document 

the procedures used, record the results, 

and make the records available to 

BSEE upon request. You must maintain your records on the rig for 2 years 

from the date the records are created, 

or for a longer period if directed by 

BSEE. 

(2) You must visually inspect your 

BOP system and marine riser at least 

once every 3 days if weather and sea 

conditions permit. You may use television cameras to inspect this equipment. The BSEE District Manager may 

approve alternate methods and frequencies to inspect a marine riser. 

(b) BOP maintenance. You must maintain your BOP system to ensure that 

the equipment functions properly. The 

BOP maintenance must meet or exceed 

the provisions of Sections 17.11 and 

18.11, Maintenance; and Sections 17.12 

and 18.12, Quality Management, described in API RP 53, Recommended 

Practices for Blowout Prevention 

Equipment Systems for Drilling Wells 

(incorporated by reference as specified 

in §250.198). You must document how 

you met or exceeded the provisions of 

Sections 17.11 and 18.11, Maintenance; 

and Sections 17.12 and 18.12, Quality 

Management, described in API RP 53, 

document the procedures used, record 

the results, and make the records 

available to BSEE upon request. You 

must maintain your records on the rig 

for 2 years from the date the records 

are created, or for a longer period if directed by BSEE. 

[77 FR 50900, Aug. 22, 2012] 


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§ 250.1709 30 CFR Ch. II (7–1–13 Edition) 

§ 250.1709 What are my well-control 

fluid requirements? 

Before you displace kill-weight fluid 

from the wellbore and/or riser to an 

underbalanced state, you must obtain 

approval from the BSEE District Manager. To obtain approval, you must 

submit with your APM, your reasons 

for displacing the kill-weight fluid and 

provide detailed step-by-step written 

procedures describing how you will 

safely displace these fluids. The stepby-step displacement procedures must 

address the following: 

(a) Number and type of independent 

barriers, as described in §250.420(b)(3), 

that are in place for each flow path 

that requires such barriers, 

(b) Tests you will conduct to ensure 

integrity of independent barriers, 

(c) BOP procedures you will use while 

displacing kill weight fluids, and 

(d) Procedures you will use to monitor the volumes and rates of fluids entering and leaving the wellbore. 

[77 FR 50900, Aug. 22, 2012] 

PERMANENTLY PLUGGING WELLS

§ 250.1710 When must I permanently 

plug all wells on a lease? 

You must permanently plug all wells 

on a lease within 1 year after the lease 

terminates. 

§ 250.1711 When will BSEE order me to 

permanently plug a well? 

BSEE will order you to permanently 

plug a well if that well: 

(a) Poses a hazard to safety or the environment; or 

(b) Is not useful for lease operations 

and is not capable of oil, gas, or sulphur production in paying quantities. 

§ 250.1712 What information must I 

submit before I permanently plug a 

well or zone? 

Before you permanently plug a well 

or zone, you must submit form BSEE– 

0124, Application for Permit to Modify, 

to the appropriate District Manager 

and receive approval. A request for approval must contain the following information: 

(a) The reason you are plugging the 

well (or zone), for completions with 

production amounts specified by the 

Regional Supervisor, along with substantiating information demonstrating 

its lack of capacity for further profitable production of oil, gas, or sulfur; 

(b) Recent well test data and pressure 

data, if available; 

(c) Maximum possible surface pressure, and how it was determined; 

(d) Type and weight of well-control 

fluid you will use; 

(e) A description of the work; 

(f) A current and proposed well schematic and description that includes: 

(1) Well depth; 

(2) All perforated intervals that have 

not been plugged; 

(3) Casing and tubing depths and details; 

(4) Subsurface equipment; 

(5) Estimated tops of cement (and the 

basis of the estimate) in each casing 

annulus; 

(6) Plug locations; 

(7) Plug types; 

(8) Plug lengths; 

(9) Properties of mud and cement to 

be used; 

(10) Perforating and casing cutting 

plans; 

(11) Plug testing plans; 

(12) Casing removal (including information on explosives, if used); 

(13) Proposed casing removal depth; 

and 

(14) Your plans to protect archaeological and sensitive biological features, including anchor damage during 

plugging operations, a brief assessment 

of the environmental impacts of the 

plugging operations, and the procedures and mitigation measures you will 

take to minimize such impacts; and 

(g) Certification by a Registered Professional Engineer of the well abandonment design and procedures and that 

all plugs meet the requirements in the 

table in §250.1715. In addition to the requirements of §250.1715, the Registered 

Professional Engineer must also certify 

the design will include two independent 

barriers, one of which must be a mechanical barrier, in the center wellbore 

as described in §250.420(b)(3). The Registered Professional Engineer must be 

registered in a State of the United 

States and have sufficient expertise 


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Safety & Environmental Enforcement, Interior § 250.1715 

and experience to perform the certification. You must submit this certification with your APM (Form BSEE– 

0124). 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50900, Aug. 22, 2012] 

§ 250.1713 Must I notify BSEE before I 

begin well plugging operations? 

You must notify the appropriate District Manager at least 48 hours before 

beginning operations to permanently 

plug a well. 

§ 250.1714 What must I accomplish 

with well plugs? 

You must ensure that all well plugs: 

(a) Provide downhole isolation of hydrocarbon and sulphur zones; 

(b) Protect freshwater aquifers; and 

(c) Prevent migration of formation 

fluids within the wellbore or to the 

seafloor. 

§ 250.1715 How must I permanently 

plug a well? 

(a) You must permanently plug wells 

according to the table in this section. 

The District Manager may require additional well plugs as necessary. 

PERMANENT WELL PLUGGING REQUIREMENTS

If you have . . . Then you must use . . . 

(1) Zones in open hole, Cement plug(s) set from at least 100 feet below the bottom to 100 feet above the 

top of oil, gas, and fresh-water zones to isolate fluids in the strata.

(2) Open hole below casing, (i) A cement plug, set by the displacement method, at least 100 feet above and 

below deepest casing shoe; 

(ii) A cement retainer with effective back-pressure control set 50 to 100 feet 

above the casing shoe, and a cement plug that extends at least 100 feet below 

the casing shoe and at least 50 feet above the retainer; or 

(iii) A bridge plug set 50 feet to 100 feet above the shoe with 50 feet of cement 

on top of the bridge plug, for expected or known lost circulation conditions.

(3) A perforated zone that is currently 

open and not previously squeezed or 

isolated, 

(i) A method to squeeze cement to all perforations; 

(ii) A cement plug set by the displacement method, at least 100 feet above to 100 

feet below the perforated interval, or down to a casing plug, whichever is less; 

or 

(iii) If the perforated zones are isolated from the hole below, you may use any of 

the plugs specified in paragraphs (a)(3)(iii)(A) through (E) of this section instead of those specified in paragraphs (a)(3)(i) and (a)(3)(ii) of this section. 

(A) A cement retainer with effective back-pressure control set 50 to 100 feet 

above the top of the perforated interval, and a cement plug that extends at 

least 100 feet below the bottom of the perforated interval with at least 50 feet 

of cement above the retainer; 

(B) A bridge plug set 50 to 100 feet above the top of the perforated interval and 

at least 50 feet of cement on top of the bridge plug; 

(C) A cement plug at least 200 feet in length, set by the displacement method, 

with the bottom of the plug no more than 100 feet above the perforated interval; 

(D) A through-tubing basket plug set no more than 100 feet above the perforated 

interval with at least 50 feet of cement on top of the basket plug; or 

(E) A tubing plug set no more than 100 feet above the perforated interval topped 

with a sufficient volume of cement so as to extend at least 100 feet above the 

uppermost packer in the wellbore and at least 300 feet of cement in the casing 

annulus immediately above the packer. 

(4) A casing stub where the stub end is 

within the casing, 

(i) A cement plug set at least 100 feet above and below the stub end; 

(ii) A cement retainer or bridge plug set at least 50 to 100 feet above the stub 

end with at least 50 feet of cement on top of the retainer or bridge plug; or 

(iii) A cement plug at least 200 feet long with the bottom of the plug set no more 

than 100 feet above the stub end. 

(5) A casing stub where the stub end is 

below the casing, 

A plug as specified in paragraph (a)(1) or (a)(2) of this section, as applicable. 

(6) An annular space that communicates 

with open hole and extends to the mud 

line, 

A cement plug at least 200 feet long set in the annular space. For a well completed above the ocean surface, you must pressure test each casing annulus 

to verify isolation. 

(7) A subsea well with unsealed annulus, A cutter to sever the casing, and you must set a stub plug as specified in paragraphs (a)(4) and (a)(5) of this section. 

(8) A well with casing, A cement surface plug at least 150 feet long set in the smallest casing that extends to the mud line with the top of the plug no more than 150 feet below the 

mud line. 

(9) Fluid left in the hole, A fluid in the intervals between the plugs that is dense enough to exert a hydrostatic pressure that is greater than the formation pressures in the intervals. 


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§ 250.1716 30 CFR Ch. II (7–1–13 Edition) 

PERMANENT WELL PLUGGING REQUIREMENTS—Continued 

If you have . . . Then you must use . . . 

(10) Permafrost areas, (i) A fluid to be left in the hole that has a freezing point below the temperature of 

the permafrost, and a treatment to inhibit corrosion; and 

(ii) Cement plugs designed to set before freezing and have a low heat of hydration. 

(11) Removed the barriers required in 

§ 250.420(b)(3) for the well to be completed 

Two independent barriers, one of which must be a mechanical barrier, in the center wellbore as described in § 250.420(b)(3) once the well is to be placed in a 

permanent or temporary abandonment..

(b) You must test the first plug below 

the surface plug and all plugs in lost 

circulation areas that are in open hole. 

The plug must pass one of the following tests to verify plug integrity: 

(1) A pipe weight of at least 15,000 

pounds on the plug; or 

(2) A pump pressure of at least 1,000 

pounds per square inch. Ensure that 

the pressure does not drop more than 10 

percent in 15 minutes. The District 

Manager may require you to tests 

other plug(s). 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50900, Aug. 22, 2012] 

§ 250.1716 To what depth must I remove wellheads and casings? 

(a) Unless the District Manager approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at 

least 15 feet below the mud line. 

(b) The District Manager may approve an alternate removal depth if: 

(1) The wellhead or casing would not 

become an obstruction to other users 

of the seafloor or area, and 

geotechnical and other information 

you provide demonstrate that erosional 

processes capable of exposing the obstructions are not expected; or 

(2) You determine, and BSEE concurs, that you must use divers, and the 

seafloor sediment stability poses safety 

concerns; or 

(3) The water depth is greater than 

800 meters (2,624 feet). 

§ 250.1717 After I permanently plug a 

well, what information must I submit? 

Within 30 days after you permanently 

plug a well, you must submit form 

BSEE–0124, Application for Permit to 

Modify (subsequent report), to the appropriate District Manager, and include the following information: 

(a) Information included in §250.1712 

with a final well schematic; 

(b) Description of the plugging work; 

(c) Nature and quantities of material 

used in the plugs; and 

(d) If you cut and pulled any casing 

string, the following information: 

(1) A description of the methods used 

(including information on explosives, if 

used); 

(2) Size and amount of casing removed; and 

(3) Casing removal depth. 

TEMPORARY ABANDONED WELLS

§ 250.1721 If I temporarily abandon a 

well that I plan to re-enter, what 

must I do? 

You may temporarily abandon a well 

when it is necessary for proper development and production of a lease. To 

temporarily abandon a well, you must 

do all of the following: 

(a) Submit form BSEE–0124, Application for Permit to Modify, and the applicable information required by 

§250.1712 to the appropriate District 

Manager and receive approval; 

(b) Adhere to the plugging and testing requirements for permanently 

plugged wells listed in the table in 

§250.1715, except for §250.1715(a)(8). You 

do not need to sever the casings, remove the wellhead, or clear the site; 

(c) Set a bridge plug or a cement plug 

at least 100-feet long at the base of the 

deepest casing string, unless the casing 

string has been cemented and has not 

been drilled out. If a cement plug is 

set, it is not necessary for the cement 

plug to extend below the casing shoe 

into the open hole; 

(d) Set a retrievable or a permanenttype bridge plug or a cement plug at 

least 100 feet long in the inner-most 

casing. The top of the bridge plug or 

cement plug must be no more than 


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Safety & Environmental Enforcement, Interior § 250.1722 

1,000 feet below the mud line. BSEE 

may consider approving alternate requirements for subsea wells case-bycase; 

(e) Identify and report subsea 

wellheads, casing stubs, or other obstructions that extend above the mud 

line according to U.S. Coast Guard 

(USCG) requirements; 

(f) Except in water depths greater 

than 300 feet, protect subsea wellheads, 

casing stubs, mud line suspensions, or 

other obstructions remaining above the 

seafloor by using one of the following 

methods, as approved by the District 

Manager or Regional Supervisor: 

(1) A caisson designed according to 30 

CFR 250, subpart I, and equipped with 

aids to navigation; 

(2) A jacket designed according to 30 

CFR 250, subpart I, and equipped with 

aids to navigation; or 

(3) A subsea protective device that 

meets the requirements in §250.1722. 

(g) Within 30 days after you temporarily plug a well, you must submit 

form BSEE–0124, Application for Permit to Modify (subsequent report), and 

include the following information: 

(1) Information included in §250.1712 

with a well schematic; 

(2) Information required by 

§250.1717(b), (c), and (d); and 

(3) A description of any remaining 

subsea wellheads, casing stubs, 

mudline suspension equipment, or 

other obstructions that extend above 

the seafloor; and 

(h) Submit certification by a Registered Professional Engineer of the 

well abandonment design and procedures and that all plugs meet the requirements of paragraph (b) of this section. In addition to the requirements of 

paragraph (b) of this section, the Registered Professional Engineer must 

also certify the design will include two 

independent barriers, one of which 

must be a mechanical barrier, in the 

center wellbore as described in 

§250.420(b)(3). The Registered Professional Engineer must be registered in a 

State of the United States and have 

sufficient expertise and experience to 

perform the certification. You must 

submit this certification with your 

APM (Form BSEE–0124) required by 

§250.1712 of this part. 

[76 FR 64462, Oct. 18, 2011, as amended at 77 

FR 50900, Aug. 22, 2012] 

§ 250.1722 If I install a subsea protective device, what requirements 

must I meet? 

If you install a subsea protective device under §250.1721(f)(3), you must install it in a manner that allows fishing 

gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear. 

(a) Use form BSEE–0124, Application 

for Permit to Modify to request approval from the appropriate District 

Manager to install a subsea protective 

device. 

(b) The protective device may not extend more than 10 feet above the 

seafloor (unless BSEE approves otherwise). 

(c) You must trawl over the protective device when you install it (adhere 

to the requirements at §250.1741(d) 

through (h)). If the trawl does not pass 

over the protective device or causes 

damage to it, you must notify the appropriate District Manager within 5 

days and perform remedial action within 30 days of the trawl; 

(d) Within 30 days after you complete 

the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Manager using form BSEE–0124, Application for Permit to Modify that includes 

the following: 

(1) The date(s) the trawling test was 

performed and the vessel that was 

used; 

(2) A plat at an appropriate scale 

showing the trawl lines; 

(3) A description of the trawling operation and the net(s) that were used; 

(4) An estimate by the trawling contractor of the seafloor penetration 

depth achieved by the trawl; 

(5) A summary of the results of the 

trawling test including a discussion of 

any snags and interruptions, a description of any damage to the protective 

covering, the casing stub or mud line 

suspension equipment, or the trawl, 

and a discussion of any snag removals 

requiring diver assistance; and 


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§ 250.1723 30 CFR Ch. II (7–1–13 Edition) 

(6) A letter signed by your authorized 

representative stating that he/she witnessed the trawling test. 

(e) If a temporarily abandoned well is 

protected by a subsea device installed 

in a water depth less than 100 feet, 

mark the site with a buoy installed according to the USCG requirements. 

(f) Provide annual reports to the Regional Supervisor describing your plans 

to either re-enter and complete the 

well or to permanently plug the well. 

(g) Ensure that all subsea wellheads, 

casing stubs, mud line suspensions, or 

other obstructions in water depths less 

than 300 feet remain protected. 

(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least 

annually. 

(2) If the inspection reveals that a 

casing stub or mud line suspension is 

no longer properly protected, or if the 

trawl does not pass over the subsea 

protective covering without causing 

damage to the covering, the casing 

stub or mud line suspension equipment, 

or the trawl, notify the appropriate 

District Manager within 5 days, and 

perform the necessary remedial work 

within 30 days of discovery of the problem. 

(3) In your annual report required by 

paragraph (f) of this section, include 

the inspection date, results, and method used and a description of any remedial work you will perform or have performed. 

(h) You may request approval to 

waive the trawling test required by 

paragraph (c) of this section if you plan 

to use either: 

(1) A buoy with automatic tracking 

capabilities installed and maintained 

according to USCG requirements at 33 

CFR part 67 (or its successor); or 

(2) A design and installation method 

that has been proven successful by 

trawl testing of previous protective devices of the same design and installed 

in areas with similar bottom conditions. 

§ 250.1723 What must I do when it is 

no longer necessary to maintain a 

well in temporary abandoned status? 

If you or BSEE determines that continued maintenance of a well in a temporary abandoned status is not necessary for the proper development or 

production of a lease, you must: 

(a) Promptly and permanently plug 

the well according to §250.1715; 

(b) Remove any casing stub or mud 

line suspension equipment and any 

subsea protective covering. You must 

submit a request for approval to perform such work to the appropriate District Manager using form BSEE–0124, 

Application for Permit to Modify; and 

(c) Clear the well site according to 

§§250.1740 through 250.1742. 

REMOVING PLATFORMS AND OTHER

FACILITIES

§ 250.1725 When do I have to remove 

platforms and other facilities? 

(a) You must remove all platforms 

and other facilities within 1 year after 

the lease or pipeline right-of-way terminates, unless you receive approval to 

maintain the structure to conduct 

other activities. Platforms include production platforms, well jackets, singlewell caissons, and pipeline accessory 

platforms. Other activities include 

those supporting OCS oil and gas production and transportation, as well as 

other energy-related or marine-related 

uses (including LNG) for which adequate financial assurance for decommissioning has been provided to a Federal agency which has given BSEE a 

commitment that it has and will exercise authority to compel the performance of decommissioning within a time 

following cessation of the new use acceptable to BSEE. The approval will 

specify: 

(1) Whether you must continue to 

maintain any financial assurance for 

decommissioning; and 

(2) Whether, and under what circumstances, you must perform any decommissioning not performed by the 

new facility owner/user. 

(b) Before you may remove a platform or other facility, you must submit a final removal application to the 

Regional Supervisor for approval and 


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Safety & Environmental Enforcement, Interior § 250.1727 

include the information listed in 

§250.1727. 

(c) You must remove a platform or 

other facility according to the approved application. 

(d) You must flush all production risers with seawater before you remove 

them. 

(e) You must notify the Regional Supervisor at least 48 hours before you 

begin the removal operations. 

§ 250.1726 When must I submit an initial platform removal application 

and what must it include? 

An initial platform removal application is required only for leases and 

pipeline rights-of-way in the Pacific 

OCS Region or the Alaska OCS Region. 

It must include the following information: 

(a) Platform or other facility removal procedures, including the types 

of vessels and equipment you will use; 

(b) Facilities (including pipelines) 

you plan to remove or leave in place; 

(c) Platform or other facility transportation and disposal plans; 

(d) Plans to protect marine life and 

the environment during decommissioning operations, including a brief assessment of the environmental impacts 

of the operations, and procedures and 

mitigation measures that you will take 

to minimize the impacts; and 

(e) A projected decommissioning 

schedule. 

§ 250.1727 What information must I include in my final application to remove a platform or other facility? 

You must submit to the Regional Supervisor, a final application for approval to remove a platform or other 

facility. Your application must be accompanied by payment of the service 

fee listed in §250.125. If you are proposing to use explosives, provide three 

copies of the application. If you are not 

proposing to use explosives, provide 

two copies of the application. Include 

the following information in the final 

removal application, as applicable: 

(a) Identification of the applicant including: 

(1) Lease operator/pipeline right-ofway holder; 

(2) Address; 

(3) Contact person and telephone 

number; and 

(4) Shore base. 

(b) Identification of the structure 

you are removing including: 

(1) Platform Name/BSEE Complex ID 

Number; 

(2) Location (lease/right-of-way, area, 

block, and block coordinates); 

(3) Date installed (year); 

(4) Proposed date of removal (Month/ 

Year); and 

(5) Water depth. 

(c) Description of the structure you 

are removing including: 

(1) Configuration (attach a photograph or a diagram); 

(2) Size; 

(3) Number of legs/casings/pilings; 

(4) Diameter and wall thickness of 

legs/casings/pilings; 

(5) Whether piles are grouted inside 

or outside; 

(6) Brief description of soil composition and condition; 

(7) The sizes and weights of the jacket, topsides (by module), conductors, 

and pilings; and 

(8) The maximum removal lift weight 

and estimated number of main lifts to 

remove the structure. 

(d) A description, including anchor 

pattern, of the vessel(s) you will use to 

remove the structure. 

(e) Identification of the purpose, including: 

(1) Lease expiration/right-of-way relinquishment date; and 

(2) Reason for removing the structure. 

(f) A description of the removal 

method, including: 

(1) A brief description of the method 

you will use; 

(2) If you are using explosives, the 

following: 

(i) Type of explosives; 

(ii) Number and sizes of charges; 

(iii) Whether you are using single 

shot or multiple shots; 

(iv) If multiple shots, the sequence 

and timing of detonations; 

(v) Whether you are using a bulk or 

shaped charge; 

(vi) Depth of detonation below the 

mud line; and 

(vii) Whether you are placing the explosives inside or outside of the pilings; 

(3) If you will use divers or acoustic 

devices to conduct a pre-removal survey to detect the presence of turtles 


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§ 250.1728 30 CFR Ch. II (7–1–13 Edition) 

and marine mammals, a description of 

the proposed detection method; and 

(4) A statement whether or not you 

will use transducers to measure the 

pressure and impulse of the detonations. 

(g) Your plans for transportation and 

disposal (including as an artificial reef) 

or salvage of the removed platform. 

(h) If available, the results of any recent biological surveys conducted in 

the vicinity of the structure and recent 

observations of turtles or marine mammals at the structure site. 

(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation 

measures you will take to minimize 

such impacts. 

(j) A statement whether or not you 

will use divers to survey the area after 

removal to determine any effects on 

marine life. 

§ 250.1728 To what depth must I remove a platform or other facility? 

(a) Unless the Regional Supervisor 

approves an alternate depth under 

paragraph (b) of this section, you must 

remove all platforms and other facilities (including templates and pilings) 

to at least 15 feet below the mud line. 

(b) The Regional Supervisor may approve an alternate removal depth if: 

(1) The remaining structure would 

not become an obstruction to other 

users of the seafloor or area, and 

geotechnical and other information 

you provide demonstrate that erosional 

processes capable of exposing the obstructions are not expected; or 

(2) You determine, and BSEE concurs, that you must use divers and the 

seafloor sediment stability poses safety 

concerns; or 

(3) The water depth is greater than 

800 meters (2,624 feet). 

§ 250.1729 After I remove a platform or 

other facility, what information 

must I submit? 

Within 30 days after you remove a 

platform or other facility, you must 

submit a written report to the Regional Supervisor that includes the following: 

(a) A summary of the removal operation including the date it was completed; 

(b) A description of any mitigation 

measures you took; and 

(c) A statement signed by your authorized representative that certifies 

that the types and amount of explosives you used in removing the platform or other facility were consistent 

with those set forth in the approved removal application. 

§ 250.1730 When might BSEE approve 

partial structure removal or toppling in place? 

The Regional Supervisor may grant a 

departure from the requirement to remove a platform or other facility by 

approving partial structure removal or 

toppling in place for conversion to an 

artificial reef if you meet the following 

conditions: 

(a) The structure becomes part of a 

State artificial reef program, and the 

responsible State agency acquires a 

permit from the U.S. Army Corps of 

Engineers and accepts title and liability for the structure; and 

(b) You satisfy any U.S. Coast Guard 

(USCG) navigational requirements for 

the structure. 

§ 250.1731 Who is responsible for decommissioning an OCS facility subject to an Alternate Use RUE? 

(a) The holder of an Alternate Use 

RUE issued under 30 CFR part 585 is responsible for all decommissioning obligations that accrue following the 

issuance of the Alternate Use RUE and 

which pertain to the Alternate Use 

RUE. See 30 CFR part 585, subpart J, 

for additional information concerning 

the decommissioning responsibilities of 

an Alternate Use RUE grant holder. 

(b) The lessee under the lease originally issued under 30 CFR part 556 will 

remain responsible for decommissioning obligations that accrued before 

issuance of the Alternate Use RUE, as 

well as for decommissioning obligations that accrue following issuance of 

the Alternate Use RUE to the extent 

associated with continued activities 

authorized under this part. 


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Safety & Environmental Enforcement, Interior § 250.1741 

(c) If a lease issued under 30 CFR part 

556 is cancelled or otherwise terminated under any provision of this subchapter, the lessee, upon our approval, 

may defer removal of any OCS facility 

within the lease area that is subject to 

an Alternate Use RUE. If we elect to 

grant such a deferral, the lessee remains responsible for removing the facility upon termination of the Alternate Use RUE and will be required to 

retain sufficient bonding or other financial assurances to ensure that the 

structure is removed or otherwise decommissioned in accordance with the 

provisions of this subpart. 

SITE CLEARANCE FOR WELLS, 

PLATFORMS, AND OTHER FACILITIES

§ 250.1740 How must I verify that the 

site of a permanently plugged well, 

removed platform, or other removed facility is clear of obstructions? 

Within 60 days after you permanently 

plug a well or remove a platform or 

other facility, you must verify that the 

site is clear of obstructions by using 

one of the following methods: 

(a) For a well site, you must either: 

(1) Drag a trawl over the site; 

(2) Scan across the location using 

sonar equipment; 

(3) Inspect the site using a diver; 

(4) Videotape the site using a camera 

on a remotely operated vehicle (ROV); 

or 

(5) Use another method approved by 

the District Manager if the particular 

site conditions warrant. 

(b) For a platform or other facility 

site in water depths less than 300 feet, 

you must drag a trawl over the site. 

(c) For a platform or other facility 

site in water depths 300 feet or more, 

you must either: 

(1) Drag a trawl over the site; 

(2) Scan across the site using sonar 

equipment; or 

(3) Use another method approved by 

the Regional Supervisor if the particular site conditions warrant. 

§ 250.1741 If I drag a trawl across a 

site, what requirements must I 

meet? 

If you drag a trawl across the site in 

accordance with §250.1740, you must 

meet all of the requirements of this 

section. 

(a) You must drag the trawl in a gridlike pattern as shown in the following 

table: 

For a . . . You must drag the trawl across a . . . 

(1) Well site, 300-foot-radius circle centered on the well location. 

(2) Subsea well site, 600-foot-radius circle centered on the well location. 

(3) Platform site, 1,320-foot-radius circle centered on the location of the platform. 

(4) Single-well caisson, well protector jacket, template, or manifold, 600-foot-radius circle centered on the structure location. 

(b) You must trawl 100 percent of the 

limits described in paragraph (a) of 

this section in two directions. 

(c) You must mark the area to be 

cleared as a hazard to navigation according to USCG requirements until 

you complete the site clearance procedures. 

(d) You must use a trawling vessel 

equipped with a calibrated navigational positioning system capable of 

providing position accuracy of ±30 feet. 

(e) You must use a trawling net that 

is representative of those used in the 

commercial fishing industry (one that 

has a net strength equal or greater 

than that provided by No. 18 twine). 

(f) You must ensure that you trawl 

no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological feature. 

(g) If you trawl near an active pipeline, you must meet the requirements 

in the following table: 

For . . . You must trawl . . . And you must . . . 

(1) Buried active pipelines, First contact the pipeline owner or operator to determine the condition of the 

pipeline before trawling over the buried pipeline. 


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§ 250.1742 30 CFR Ch. II (7–1–13 Edition) 

For . . . You must trawl . . . And you must . . . 

(2) Unburied active pipelines that are 8 

inches in diameter or larger, 

no closer than 100 feet to the either side 

of the pipeline, 

Trawl parallel to the pipeline Do not 

trawl across the pipeline. 

(3) Unburied smaller diameter active pipelines in the trawl area that have obstructions (e.g., pipeline valves) 

present, 

no closer than 100 feet to either side of 

the pipeline, 

Trawl parallel to the pipeline. Do not 

trawl across the pipeline. 

(4) Unburied active pipelines in the trawl 

area that are smaller than 8 inches in 

diameter and have no obstructions 

present, 

parallel to the pipeline, 

(h) You must ensure that any trawling contractor you may use: 

(1) Has no corporate or other financial ties to you; and 

(2) Has a valid commercial trawling 

license for both the vessel and its captain. 

§ 250.1742 What other methods can I 

use to verify that a site is clear? 

If you do not trawl a site, you can 

verify that the site is clear of obstructions by using any of the methods 

shown in the following table: 

If you use . . . You must . . . And you must . . . 

(a) Sonar, cover 100 percent of the appropriate grid 

area listed in § 250.1741(a), 

Use a sonar signal with a frequency of 

at least 500 kHz. 

(b) A diver, ensure that the diver visually inspects 

100 percent of the appropriate grid 

area listed in § 250.1741(a), 

Ensure that the diver uses a search pattern of concentric circles or parallel 

lines spaced no more than 10 feet 

apart. 

(c) An ROV (remotely operated vehicle), ensure that the ROV camera records 

videotape over 100 percent of the appropriate grid area listed in 

§ 250.1741(a), 

Ensure that the ROV uses a pattern of 

concentric circles or parallel lines 

spaced no more than 10 feet apart. 

§ 250.1743 How do I certify that a site 

is clear of obstructions? 

(a) For a well site, you must submit 

to the appropriate District Manager 

within 30 days after you complete the 

verification activities a form BSEE– 

0124, Application for Permit to Modify, 

to include the following information: 

(1) A signed certification that the 

well site area is cleared of all obstructions; 

(2) The date the verification work 

was performed and the vessel used; 

(3) The extent of the area surveyed; 

(4) The survey method used; 

(5) The results of the survey, including a list of any debris removed or a 

statement from the trawling contractor that no objects were recovered; 

and 

(6) A post-trawling job plot or map 

showing the trawled area. 

(b) For a platform or other facility 

site, you must submit the following information to the appropriate Regional 

Supervisor within 30 days after you 

complete the verification activities: 

(1) A letter signed by an authorized 

company official certifying that the 

platform or other facility site area is 

cleared of all obstructions and that a 

company representative witnessed the 

verification activities; 

(2) A letter signed by an authorized 

official of the company that performed 

the verification work for you certifying 

that it cleared the platform or other 

facility site area of all obstructions; 

(3) The date the verification work 

was performed and the vessel used; 

(4) The extent of the area surveyed; 

(5) The survey method used; 

(6) The results of the survey, including a list of any debris removed or a 

statement from the trawling contractor that no objects were recovered; 

and 

(7) A post-trawling job plot or map 

showing the trawled area. 


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Safety & Environmental Enforcement, Interior § 250.1900 

PIPELINE DECOMMISSIONING

§ 250.1750 When may I decommission a 

pipeline in place? 

You may decommission a pipeline in 

place when the Regional Supervisor determines that the pipeline does not 

constitute a hazard (obstruction) to 

navigation and commercial fishing operations, unduly interfere with other 

uses of the OCS, or have adverse environmental effects. 

§ 250.1751 How do I decommission a 

pipeline in place? 

You must do the following to decommission a pipeline in place: 

(a) Submit a pipeline decommissioning application in triplicate to the 

Regional Supervisor for approval. Your 

application must be accompanied by 

payment of the service fee listed in 

§250.125. Your application must include 

the following information: 

(1) Reason for the operation; 

(2) Proposed decommissioning procedures; 

(3) Length (feet) of segment to be decommissioned; and 

(4) Length (feet) of segment remaining. 

(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; 

(c) Flush the pipeline; 

(d) Fill the pipeline with seawater; 

(e) Cut and plug each end of the pipeline; 

(f) Bury each end of the pipeline at 

least 3 feet below the seafloor or cover 

each end with protective concrete 

mats, if required by the Regional Supervisor; and 

(g) Remove all pipeline valves and 

other fittings that could unduly interfere with other uses of the OCS. 

§ 250.1752 How do I remove a pipeline? 

Before removing a pipeline, you 

must: 

(a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval. Your application 

must be accompanied by payment of 

the service fee listed in §250.125. Your 

application must include the following 

information: 

(1) Proposed removal procedures; 

(2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you 

will use to remove the pipeline; 

(3) Length (feet) to be removed; 

(4) Length (feet) of the segment that 

will remain in place; 

(5) Plans for transportation of the removed pipe for disposal or salvage; 

(6) Plans to protect archaeological 

and sensitive biological features during 

removal operations, including a brief 

assessment of the environmental impacts of the removal operations and 

procedures and mitigation measures 

that you will take to minimize such 

impacts; and 

(7) Projected removal schedule and 

duration. 

(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and 

(c) Flush the pipeline. 

§ 250.1753 After I decommission a pipeline, what information must I submit? 

Within 30 days after you decommission a pipeline, you must submit a 

written report to the Regional Supervisor that includes the following: 

(a) A summary of the decommissioning operation including the date it 

was completed; 

(b) A description of any mitigation 

measures you took; and 

(c) A statement signed by your authorized representative that certifies 

that the pipeline was decommissioned 

according to the approved application. 

§ 250.1754 When must I remove a pipeline decommissioned in place? 

You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is 

an obstruction. 

Subpart R [Reserved] 

Subpart S—Safety and Environmental Management Systems 

(SEMS) 

§ 250.1900 Must I have a SEMS program? 

You must develop, implement, and 

maintain a safety and environmental 

management system (SEMS) program. 


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§ 250.1901 30 CFR Ch. II (7–1–13 Edition) 

Your SEMS program must address the 

elements described in §250.1902, American Petroleum Institute’s Recommended Practice for Development of 

a Safety and Environmental Management Program for Offshore Operations 

and Facilities (API RP 75) (as incorporated by reference in §250.198), and 

other requirements as identified in this 

subpart. 

(a) If there are any conflicts between 

the requirements of this subpart and 

API RP 75; COS–2–01, COS–2–03, or COS– 

2–04; or ISO/IEC 17011 (incorporated by 

reference as specified in §250.198), you 

must follow the requirements of this 

subpart. 

(b) Nothing in this subpart affects 

safety or other matters under the jurisdiction of the Coast Guard. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20440, Apr. 5, 2013] 

§ 250.1901 What is the goal of my 

SEMS program? 

The goal of your SEMS program is to 

promote safety and environmental protection by ensuring all personnel 

aboard a facility are complying with 

the policies and procedures identified 

in your SEMS. 

(a) To accomplish this goal, you must 

ensure that your SEMS program identifies, addresses, and manages safety, 

environmental hazards, and impacts 

during the design, construction, startup, operation (including, but not limited to, drilling and decommissioning), 

inspection, and maintenance of all new 

and existing facilities, including mobile offshore drilling units (MODUs) 

when attached to the seabed and Department of the Interior (DOI) regulated pipelines. 

(b) All personnel involved with your 

SEMS program must be trained to have 

the skills and knowledge to perform 

their assigned duties. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20440, Apr. 5, 2013] 

§ 250.1902 What must I include in my 

SEMS program? 

You must have a properly documented SEMS program in place and 

make it available to BSEE upon request as required by §250.1924(b). 

(a) Your SEMS program must meet 

the minimum criteria outlined in this 

subpart, including the following SEMS 

program elements: 

(1) General (see §250.1909) 

(2) Safety and Environmental Information (see §250.1910) 

(3) Hazards Analysis (see §250.1911) 

(4) Management of Change (see 

§250.1912) 

(5) Operating Procedures (see 

§250.1913) 

(6) Safe Work Practices (see §250.1914) 

(7) Training (see §250.1915) 

(8) Mechanical Integrity (Assurance 

of Quality and Mechanical Integrity of 

Critical Equipment) (see §250.1916) 

(9) Pre-startup Review (see §250.1917) 

(10) Emergency Response and Control 

(see §250.1918) 

(11) Investigation of Incidents (see 

§250.1919) 

(12) Auditing (Audit of Safety and 

Environmental Management Program 

Elements) (see §250.1920) 

(13) Recordkeeping (Records and Documentation) and additional BSEE requirements (see §250.1928) 

(14) Stop Work Authority (SWA) (see 

§250.1930) 

(15) Ultimate Work Authority (UWA) 

(see §250.1931) 

(16) Employee Participation Plan 

(EPP) (see §250.1932) 

(17) Reporting Unsafe Working Conditions (see §250.1933). 

(b) You must include a job safety 

analysis (JSA) for OCS activities identified or discussed in your SEMS program (see §250.1911). 

(c) Your SEMS program must meet 

or exceed the standards of safety and 

environmental protection of API RP 75 

(as incorporated by reference in 

§250.198). 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20440, Apr. 5, 2013] 

§ 250.1903 Acronyms and definitions. 

Definitions listed in this section 

apply to this subpart and supersede 

definitions in API RP 75, Appendices D 

and E; COS–2–01, COS–2–03, and COS–2– 

04; and ISO/IEC 17011 (incorporated by 

reference as specified in §250.198). 

(a) Acronyms used frequently in this 

subpart have the following meanings: 

AB means Accreditation Body, 

ASP means Audit Service Provider, 

CAP means Corrective Action Plan, 


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Safety & Environmental Enforcement, Interior § 250.1909 

COS means Center for Offshore Safety, 

EPP means Employee Participation 

Plan, 

ISO means International Organization for Standardization, 

JSA means Job Safety Analysis, 

MODU means Mobile Offshore Drilling Unit, 

OCS means Outer Continental Shelf, 

SEMS means Safety and Environmental Management Systems, 

SWA means Stop Work Authority, 

USCG means United States Coast 

Guard, and 

UWA means Ultimate Work Authority. 

(b) Terms used in this subpart are 

listed alphabetically as follows: 

Accreditation Body (AB) means a 

BSEE-approved independent thirdparty organization that assesses and 

accredits ASPs. 

Audit Service Provider (ASP) means an 

independent third-party organization 

that demonstrates competence to conduct SEMS audits in accordance with 

the requirements of this subpart. 

Corrective Action Plan (CAP) means a 

scheduled plan to correct deficiencies 

identified during an audit and that is 

developed by an operator following the 

issuance of an audit report. 

Personnel means direct employee(s) of 

the operator and contracted workers. 

Ultimate Work Authority (UWA) means 

the authority assigned to an individual 

or position to make final decisions relating to activities and operations on 

the facility. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20440, Apr. 5, 2013] 

§ 250.1904 Special instructions. 

(a) For purposes of this subpart, each 

and every reference in COS–2–01, COS– 

2–03, and COS–2–04 (incorporated by reference as specified in §250.198) to the 

term deepwater means the entire OCS, 

including all water depths. 

(b) The BSEE does not incorporate by 

reference any requirement that you 

must be a COS member company. For 

purposes of this subpart, each and 

every reference in COS–2–01, COS–2–03, 

and COS–2–04 to the phrase COS member 

company(ies) means you, whether or not 

you are a COS member. 

(c) For purposes of this subpart, each 

and every reference in the relevant sections of COS–2–01, COS–2–03, and COS– 

2–04 (incorporated by reference as specified in §250.198) to the Center for Offshore Safety or COS means accreditation 

body or AB. 

(d) For purposes of this subpart, each 

and every reference in ISO/IEC 17011 

(incorporated by reference as specified 

in §250.198) to conformity assessment 

body (CAB) means ASP. 

[78 FR 20441, Apr. 5, 2013] 

§§ 250.1905–250.1908 [Reserved] 

§ 250.1909 What are management’s 

general responsibilities for the 

SEMS program? 

You, through your management, 

must require that the program elements discussed in API RP 75 (as incorporated by reference in §250.198) and in 

this subpart are properly documented 

and are available at field and office locations, as appropriate for each program element. You, through your management, are responsible for the development, support, continued improvement, and overall success of your 

SEMS program. Specifically you, 

through your management, must: 

(a) Establish goals and performance 

measures, demand accountability for 

implementation, and provide necessary 

resources for carrying out an effective 

SEMS program. 

(b) Appoint management representatives who are responsible for establishing, implementing and maintaining 

an effective SEMS program. 

(c) Designate specific management 

representatives who are responsible for 

reporting to management on the performance of the SEMS program. 

(d) At intervals specified in the 

SEMS program and at least annually, 

review the SEMS program to determine if it continues to be suitable, adequate and effective (by addressing the 

possible need for changes to policy, objectives, and other elements of the program in light of program audit results, 

changing circumstances and the commitment to continual improvement) 

and document the observations, conclusions and recommendations of that 

review. 


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§ 250.1910 30 CFR Ch. II (7–1–13 Edition) 

(e) Develop and endorse a written description of your safety and environmental policies and organizational 

structure that define responsibilities, 

authorities, and lines of communication required to implement the SEMS 

program. 

(f) Utilize personnel with expertise in 

identifying safety hazards, environmental impacts, optimizing operations, 

developing safe work practices, developing training programs and investigating incidents. 

(g) Ensure that facilities are designed, constructed, maintained, monitored, and operated in a manner compatible with applicable industry codes, 

consensus standards, and generally accepted practice as well as in compliance with all applicable governmental 

regulations. 

(h) Ensure that management of safety hazards and environmental impacts 

is an integral part of the design, construction, maintenance, operation, and 

monitoring of each facility. 

(i) Ensure that suitably trained and 

qualified personnel are employed to 

carry out all aspects of the SEMS program. 

(j) Ensure that the SEMS program is 

maintained and kept up to date by 

means of periodic audits to ensure effective performance. 

§ 250.1910 What safety and environmental information is required? 

(a) You must require that SEMS program safety and environmental information be developed and maintained 

for any facility that is subject to the 

SEMS program. 

(b) SEMS program safety and environmental information must include: 

(1) Information that provides the 

basis for implementing all SEMS program elements, including the requirements of hazard analysis (§250.1911); 

(2) process design information including, as appropriate, a simplified process flow diagram and acceptable upper 

and lower limits, where applicable, for 

items such as temperature, pressure, 

flow and composition; and 

(3) mechanical design information including, as appropriate, piping and instrument diagrams; electrical area 

classifications; equipment arrangement drawings; design basis of the relief system; description of alarm, shutdown, and interlock systems; description of well control systems; and design basis for passive and active fire 

protection features and systems and 

emergency evacuation procedures. 

§ 250.1911 What hazards analysis criteria must my SEMS program meet? 

You must ensure that a hazards analysis (facility level) and a JSA (operations/task level) are developed and 

implemented for all of your facilities 

and activities identified or discussed in 

your SEMS. You must document and 

maintain a current analysis for each 

operation covered by this section for 

the life of the operation at the facility. 

You must update the analysis when an 

internal audit is conducted to ensure 

that it is consistent with your facility’s current operations. 

(a) Hazards analysis (facility level). 

The hazards analysis must be appropriate for the complexity of the operation and must identify, evaluate, and 

manage the hazards involved in the operation. 

(1) The hazards analysis must address 

the following: 

(i) Hazards of the operation; 

(ii) Previous incidents related to the 

operation you are evaluating, including 

any incident in which you were issued 

an Incident of Noncompliance or a civil 

or criminal penalty; 

(iii) Control technology applicable to 

the operation your hazards analysis is 

evaluating; and 

(iv) A qualitative evaluation of the 

possible safety and health effects on 

employees, and potential impacts to 

the human and marine environments, 

which may result if the control technology fails. 

(2) The hazards analysis must be performed by a person(s) with experience 

in the operations being evaluated. 

These individuals also need to be experienced in the hazards analysis methodologies being employed. 

(3) You should assure that the recommendations in the hazards analysis 

are resolved and that the resolution is 

documented. 

(4) A single hazards analysis can be 

performed to fulfill the requirements 

for simple and nearly identical facilities, such as well jackets and single 


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Safety & Environmental Enforcement, Interior § 250.1913 

well caissons. You can apply this single 

hazards analysis to simple and nearly 

identical facilities after you verify 

that any site-specific deviations are 

addressed in each of your SEMS program elements. 

(b) JSA. You must ensure a JSA is 

prepared, conducted, and approved for 

OCS activities that are identified or 

discussed in your SEMS program. The 

JSA is a technique used to identify 

risks to personnel associated with their 

job activities. The JSAs are also used 

to determine the appropriate mitigation measures needed to reduce job 

risks to personnel. The JSA must include all personnel involved with the 

job activity. 

(1) You must ensure that your JSA 

identifies, analyzes, and records: 

(i) The steps involved in performing a 

specific job; 

(ii) The existing or potential safety, 

health, and environmental hazards associated with each step; and 

(iii) The recommended action(s) and/ 

or procedure(s) that will eliminate or 

reduce these hazards, the risk of a 

workplace injury or illness, or environmental impacts. 

(2) The immediate supervisor of the 

crew performing the job onsite must 

conduct the JSA, sign the JSA, and ensure that all personnel participating in 

the job understand and sign the JSA. 

(3) The individual you designate as 

being in charge of the facility must approve and sign all JSAs before personnel start the job. 

(4) If a particular job is conducted on 

a recurring basis, and if the parameters 

of these recurring jobs do not change, 

then the person in charge of the job 

may decide that a JSA for each individual job is not required. The parameters you must consider in making this 

determination include, but are not limited to, changes in personnel, procedures, equipment, and environmental 

conditions associated with the job. 

(c) All personnel, which includes contractors, must be trained in accordance 

with the requirements of §250.1915. You 

must also verify that contractors are 

trained in accordance with §250.1915 

prior to performing a job. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20441, Apr. 5, 2013] 

§ 250.1912 What criteria for management of change must my SEMS program meet? 

(a) You must develop and implement 

written management of change procedures for modifications associated with 

the following: 

(1) Equipment, 

(2) Operating procedures, 

(3) Personnel changes (including contractors), 

(4) Materials, and 

(5) Operating conditions. 

(b) Management of change procedures 

do not apply to situations involving replacement in kind (such as, replacement of one component by another 

component with the same performance 

capabilities). 

(c) You must review all changes prior 

to their implementation. 

(d) The following items must be included in your management of change 

procedures: 

(1) The technical basis for the 

change; 

(2) Impact of the change on safety, 

health, and the coastal and marine environments; 

(3) Necessary time period to implement the change; and 

(4) Management approval procedures 

for the change. 

(e) Employees, including contractors 

whose job tasks will be affected by a 

change in the operation, must be informed of, and trained in, the change 

prior to startup of the process or affected part of the operation; and 

(f) If a management of change results 

in a change in the operating procedures 

of your SEMS program, such changes 

must be documented and dated. 

§ 250.1913 What criteria for operating 

procedures must my SEMS program 

meet? 

(a) You must develop and implement 

written operating procedures that provide instructions for conducting safe 

and environmentally sound activities 

involved in each operation addressed in 

your SEMS program. These procedures 

must include the job title and reporting relationship of the person or persons responsible for each of the facility’s operating areas and address the 

following: 

(1) Initial startup; 


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238 

§ 250.1914 30 CFR Ch. II (7–1–13 Edition) 

(2) Normal operations; 

(3) All emergency operations (including but not limited to medical evacuations, weather-related evacuations 

and emergency shutdown operations); 

(4) Normal shutdown; 

(5) Startup following a turnaround, 

or after an emergency shutdown; 

(6) Bypassing and flagging out-ofservice equipment; 

(7) Safety and environmental consequences of deviating from your 

equipment operating limits and steps 

required to correct or avoid this deviation; 

(8) Properties of, and hazards presented by, the chemicals used in the 

operations; 

(9) Precautions you will take to prevent the exposure of chemicals used in 

your operations to personnel and the 

environment. The precautions must include control technology, personal protective equipment, and measures to be 

taken if physical contact or airborne 

exposure occurs; 

(10) Raw materials used in your operations and the quality control procedures you used in purchasing these raw 

materials; 

(11) Control of hazardous chemical inventory; and 

(12) Impacts to the human and marine environment identified through 

your hazards analysis. 

(b) Operating procedures must be accessible to all employees involved in 

the operations. 

(c) Operating procedures must be reviewed at the conclusion of specified 

periods and as often as necessary to assure they reflect current and actual operating practices, including any 

changes made to your operations. 

(d) You must develop and implement 

safe and environmentally sound work 

practices for identified hazards during 

operations and the degree of hazard 

presented. 

(e) Review of and changes to the procedures must be documented and communicated to responsible personnel. 

§ 250.1914 What criteria must be documented in my SEMS program for 

safe work practices and contractor 

selection? 

Your SEMS program must establish 

and implement safe work practices designed to minimize the risks associated 

with operations, maintenance, modification activities, and the handling of 

materials and substances that could affect safety or the environment. Your 

SEMS program must also document 

contractor selection criteria. When selecting a contractor, you must obtain 

and evaluate information regarding the 

contractor’s safety record and environmental performance. You must ensure 

that contractors have their own written safe work practices. Contractors 

may adopt appropriate sections of your 

SEMS program. You and your contractor must document an agreement 

on appropriate contractor safety and 

environmental policies and practices 

before the contractor begins work at 

your facilities. 

(a) A contractor is anyone performing work for you. However, these 

requirements do not apply to contractors providing domestic services to you 

or other contractors. Domestic services 

include janitorial work, food and beverage service, laundry service, housekeeping, and similar activities. 

(b) You must document that your 

contracted employees are knowledgeable and experienced in the work practices necessary to perform their job in 

a safe and environmentally sound manner. Documentation of each contracted 

employee’s expertise to perform his/her 

job and a copy of the contractor’s safety policies and procedures must be 

made available to the operator and 

BSEE upon request. 

(c) Your SEMS program must include 

procedures and verification for selecting a contractor as follows: 

(1) Your SEMS program must have 

procedures that verify that contractors 

are conducting their activities in accordance with your SEMS program. 

(2) You are responsible for making 

certain that contractors have the skills 

and knowledge to perform their assigned duties and are conducting these 

activities in accordance with the requirements in your SEMS program. 

(3) You must make the results of 

your verification for selecting contractors available to BSEE upon request. 

(d) Your SEMS program must include 

procedures and verification that contractor personnel understand and can 

perform their assigned duties for activities such as, but not limited to: 


ehiers on DSK2VPTVN1PROD with CFR
239 

Safety & Environmental Enforcement, Interior § 250.1916 

(1) Installation, maintenance, or repair of equipment; 

(2) Construction, startup, and operation of your facilities; 

(3) Turnaround operations; 

(4) Major renovation; or 

(5) Specialty work. 

(e) You must: 

(1) Perform periodic evaluations of 

the performance of contract employees 

that verifies they are fulfilling their 

obligations, and 

(2) Maintain a contractor employee 

injury and illness log for 2 years related to the contractor’s work in the 

operation area, and include this information on Form BSEE–0131. 

(f) You must inform your contractors 

of any known hazards at the facility 

they are working on including, but not 

limited to fires, explosions, slips, trips, 

falls, other injuries, and hazards associated with lifting operations. 

(g) You must develop and implement 

safe work practices to control the presence, entrance, and exit of contract 

employees in operation areas. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20441, Apr. 5, 2013] 

§ 250.1915 What training criteria must 

be in my SEMS program? 

Your SEMS program must establish 

and implement a training program so 

that all personnel are trained in accordance with their duties and responsibilities to work safely and are aware 

of potential environmental impacts. 

Training must address such areas as 

operating procedures (§250.1913), safe 

work practices (§250.1914), emergency 

response and control measures 

(§250.1918), SWA (§250.1930), UWA 

(§250.1931), EPP (§250.1932), reporting 

unsafe working conditions (§250.1933), 

and how to recognize and identify hazards and how to construct and implement JSAs (§250.1911). You must document your instructors’ qualifications. 

Your SEMS program must address: 

(a) Initial training for the basic wellbeing of personnel and protection of 

the environment, and ensure that persons assigned to operate and maintain 

the facility possess the required knowledge and skills to carry out their duties and responsibilities, including 

startup and shutdown. 

(b) Periodic training to maintain understanding of, and adherence to, the 

current operating procedures, using 

periodic drills, to verify adequate retention of the required knowledge and 

skills. 

(c) Communication requirements to 

ensure that personnel will be informed 

of and trained as outlined in this section whenever a change is made in any 

of the areas in your SEMS program 

that impacts their ability to properly 

understand and perform their duties 

and responsibilities. Training and/or 

notice of the change must be given before personnel are expected to operate 

the facility. 

(d) How you will verify that the contractors are trained in the work practices necessary to understand and perform their jobs in a safe and environmentally sound manner in accordance 

with all provisions of this section. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20441, Apr. 5, 2013] 

§ 250.1916 What criteria for mechanical integrity must my SEMS program meet? 

You must develop and implement 

written procedures that provide instructions to ensure the mechanical integrity and safe operation of equipment through inspection, testing, and 

quality assurance. The purpose of mechanical integrity is to ensure that 

equipment is fit for service. Your mechanical integrity program must encompass all equipment and systems 

used to prevent or mitigate uncontrolled releases of hydrocarbons, toxic 

substances, or other materials that 

may cause environmental or safety 

consequences. These procedures must 

address the following: 

(a) The design, procurement, fabrication, installation, calibration, and 

maintenance of your equipment and 

systems in accordance with the manufacturer’s design and material specifications. 

(b) The training of each employee involved in maintaining your equipment 

and systems so that your employees 

can implement your mechanical integrity program. 

(c) The frequency of inspections and 

tests of your equipment and systems. 

The frequency of inspections and tests 


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240 

§ 250.1917 30 CFR Ch. II (7–1–13 Edition) 

must be in accordance with BSEE regulations and meet the manufacturer’s 

recommendations. Inspections and 

tests can be performed more frequently 

if determined to be necessary by prior 

operating experience. 

(d) The documentation of each inspection and test that has been performed on your equipment and systems. This documentation must identify the date of the inspection or test; 

include the name and position, and the 

signature of the person who performed 

the inspection or test; include the serial number or other identifier of the 

equipment on which the inspection or 

test was performed; include a description of the inspection or test performed; and the results of the inspection test. 

(e) The correction of deficiencies associated with equipment and systems 

that are outside the manufacturer’s 

recommended limits. Such corrections 

must be made before further use of the 

equipment and system. 

(f) The installation of new equipment 

and constructing systems. The procedures must address the application for 

which they will be used. 

(g) The modification of existing 

equipment and systems. The procedures must ensure that they are modified for the application for which they 

will be used. 

(h) The verification that inspections 

and tests are being performed. The procedures must be appropriate to ensure 

that equipment and systems are installed consistent with design specifications and the manufacturer’s instructions. 

(i) The assurance that maintenance 

materials, spare parts, and equipment 

are suitable for the applications for 

which they will be used. 

§ 250.1917 What criteria for pre-startup review must be in my SEMS program? 

Your SEMS program must require 

that the commissioning process include 

a pre-startup safety and environmental 

review for new and significantly modified facilities that are subject to this 

subpart to confirm that the following 

criteria are met: 

(a) Construction and equipment are 

in accordance with applicable specifications. 

(b) Safety, environmental, operating, 

maintenance, and emergency procedures are in place and are adequate. 

(c) Safety and environmental information is current. 

(d) Hazards analysis recommendations have been implemented as appropriate. 

(e) Training of operating personnel 

has been completed. 

(f) Programs to address management 

of change and other elements of this 

subpart are in place. 

(g) Safe work practices are in place. 

§ 250.1918 What criteria for emergency 

response and control must be in my 

SEMS program? 

Your SEMS program must require 

that emergency response and control 

plans are in place and are ready for immediate implementation. These plans 

must be validated by drills carried out 

in accordance with a schedule defined 

by the SEMS training program 

(§250.1915). The SEMS emergency response and control plans must include: 

(a) Emergency Action Plan that assigns authority and responsibility to 

the appropriate qualified person(s) at a 

facility for initiating effective emergency response and control, addressing 

emergency reporting and response requirements, and complying with all applicable governmental regulations; 

(b) Emergency Control Center(s) designated for each facility with access to 

the Emergency Action Plans, oil spill 

contingency plan, and other safety and 

environmental information (§250.1910); 

and 

(c) Training and Drills incorporating 

emergency response and evacuation 

procedures conducted periodically for 

all personnel (including contractor’s 

personnel), as required by the SEMS 

training program (§250.1915). Drills 

must be based on realistic scenarios 

conducted periodically to exercise elements contained in the facility or area 

emergency action plan. An analysis 

and critique of each drill must be conducted to identify and correct weaknesses. 


ehiers on DSK2VPTVN1PROD with CFR
241 

Safety & Environmental Enforcement, Interior § 250.1920 

§ 250.1919 What criteria for investigation of incidents must be in my 

SEMS program? 

To learn from incidents and help prevent similar incidents, your SEMS program must establish procedures for investigation of all incidents with serious safety or environmental consequences and require investigation of 

incidents that are determined by facility management or BSEE to have possessed the potential for serious safety 

or environmental consequences. Incident investigations must be initiated 

as promptly as possible, with due regard for the necessity of securing the 

incident scene and protecting people 

and the environment. Incident investigations must be conducted by personnel knowledgeable in the process involved, investigation techniques, and 

other specialties that are relevant or 

necessary. 

(a) The investigation of an incident 

must address the following: 

(1) The nature of the incident; 

(2) The factors (human or other) that 

contributed to the initiation of the incident and its escalation/control; and 

(3) Recommended changes identified 

as a result of the investigation. 

(b) A corrective action program must 

be established based on the findings of 

the investigation in order to analyze 

incidents for common root causes. The 

corrective action program must: 

(1) Retain the findings of investigations for use in the next hazard analysis update or audit; 

(2) Determine and document the response to each finding to ensure that 

corrective actions are completed; and 

(3) Implement a system whereby conclusions of investigations are distributed to similar facilities and appropriate personnel within their organization. 

§ 250.1920 What are the auditing requirements for my SEMS program? 

(a) Your SEMS program must be audited by an accredited ASP according 

to the requirements of this subpart and 

API RP 75, Section 12 (incorporated by 

reference as specified in §250.198). The 

audit process must also meet or exceed 

the criteria in Sections 9.1 through 9.8 

of Requirements for Third-party SEMS 

Auditing and Certification of Deepwater 

Operations COS–2–03 (incorporated by 

reference as specified in §250.198) or its 

equivalent. Additionally, the audit 

team lead must be an employee, representative, or agent of the ASP, and 

must not have any affiliation with the 

operator. The remaining team members may be chosen from your personnel and those of the ASP. The audit 

must be comprehensive and include all 

elements of your SEMS program. It 

must also identify safety and environmental performance deficiencies. 

(b) Your audit plan and procedures 

must meet or exceed all of the recommendations included in API RP 75 

section 12 (as specified in §250.198) and 

include information on how you addressed those recommendations. You 

must specifically address the following 

items: 

(1) Section 12.1 General. 

(2) Section 12.2 Scope. 

(3) Section 12.3 Audit Coverage. 

(4) Section 12.4 Audit Plan. You must 

submit your written Audit Plan to 

BSEE at least 30 days before the audit. 

BSEE reserves the right to modify the 

list of facilities that you propose to 

audit. 

(5) Section 12.5 Audit Frequency, except your audit interval, must not exceed 3 years after the 2-year time period for the first audit. The 3-year auditing cycle begins on the start date of 

each comprehensive audit (including 

the initial implementation audit) and 

ends on the start date of your next 

comprehensive audit. 

(6) Section 12.6 Audit Team. Your audits must be performed by an ASP as 

described in §250.1921. You must include the ASP’s qualifications in your 

audit plan. 

(c) You must submit an audit report 

of the audit findings, observations, deficiencies identified, and conclusions to 

BSEE within 60 days of the audit completion date. 

(d) You must provide BSEE with a 

copy of your CAP for addressing the deficiencies identified in your audit within 60 days of the audit completion date. 

Your CAP must include the name and 

job title of the personnel responsible 

for correcting the identified deficiency(ies). The BSEE will notify you 

as soon as practicable after receipt of 

your CAP if your proposed schedule is 


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242 

§ 250.1921 30 CFR Ch. II (7–1–13 Edition) 

not acceptable or if the CAP does not 

effectively address the audit findings. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20442, Apr. 5, 2013] 

§ 250.1921 What qualifications must 

the ASP meet? 

(a) The ASP must meet or exceed the 

qualifications, competency, and training criteria contained in Section 3 and 

Sections 6 through 10 of Qualification 

and Competence Requirements for Audit 

Teams and Auditors Performing Thirdparty SEMS Audits of Deepwater Operations, COS–2–01, (incorporated by reference as specified in §250.198) or its 

equivalent; 

(b) The ASP must be accredited by a 

BSEE-approved AB; and 

(c) The ASP must perform an audit 

in accordance with 250.1920(a). 

[78 FR 20442, Apr. 5, 2013] 

§ 250.1922 What qualifications must an 

AB meet? 

(a) In order for BSEE to approve an 

AB, the organization must satisfy the 

requirements of the International Organization for Standardization’s (ISO/ 

IEC 17011) Conformity assessment—General requirements for accreditation bodies 

accrediting conformity assessment bodies, 

First Edition 2004–09–01; Corrected 

Version 2005–02–15 (incorporated by reference as specified in §250.198) or its 

equivalent. 

(1) The AB must have an accreditation process that meets or exceeds the 

requirements contained in Section 6 of 

Requirements for Accreditation of Audit 

Service Providers Performing SEMS Audits and Certification of Deepwater Operations, COS–2–04 (incorporated by reference as specified in §250.198) or its 

equivalent, and other requirements 

specified in this subpart. Organizations 

requesting approval must submit documentation to BSEE describing the 

process for assessing an ASP for accreditation and approving, maintaining, and withdrawing the accreditation 

of an ASP. Requests for approval must 

be sent to DOI/BSEE, ATTN: Chief, Office of Offshore Regulatory Programs, 

381 Elden Street, HE–3314, Herndon, VA 

20170. 

(2) An AB may be subject to BSEE 

audits and other requirements deemed 

necessary to verify compliance with 

the accreditation requirements. 

(b) An AB must have procedures in 

place to avoid conflicts of interest with 

the ASP and make such information 

available to BSEE upon request. 

[78 FR 20442, Apr. 5, 2013] 

§ 250.1923 [Reserved] 

§ 250.1924 How will BSEE determine if 

my SEMS program is effective? 

(a) The BSEE, or its authorized representative, may evaluate or visit your 

facility(ies) to determine whether your 

SEMS program is in place, addresses 

all required elements, is effective in 

protecting worker safety and health 

and the environment, and preventing 

incidents. The BSEE, or its authorized 

representative, may evaluate any and 

all aspects of your SEMS program as 

outlined in this subpart. These evaluations or visits may be random and may 

be based upon your performance or 

that of your contractors. 

(b) For the evaluations, you must 

make the following available to BSEE 

upon request: 

(1) Your SEMS program; 

(2) Your audit team’s qualifications; 

(3) The SEMS audits conducted of 

your program; 

(4) Documents or information relevant to whether you have addressed 

and corrected the deficiencies of your 

audit; and 

(5) Other relevant documents or information. 

(c) During the site visit BSEE may 

verify that: 

(1) Personnel are following your 

SEMS program, 

(2) You can explain and demonstrate 

the procedures and policies included in 

your SEMS program; and 

(3) You can produce evidence to support the implementation of your SEMS 

program. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20442, Apr. 5, 2013] 

§ 250.1925 May BSEE direct me to conduct additional audits? 

(a) The BSEE may direct you to have 

an ASP audit of your SEMS program if 

BSEE identifies safety or non-compliance concerns based on the results of 

our inspections and evaluations, or as a 


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Safety & Environmental Enforcement, Interior § 250.1929 

result of an event. This BSEE-directed 

audit is in addition to the regular audit 

required by §250.1920. Alternatively, 

BSEE may conduct an audit. 

(1) If BSEE directs you to have an 

ASP audit, you are responsible for all 

of the costs associated with the audit, 

and 

(i) The ASP must meet the requirements of §§250.1920 and 250.1921 of this 

subpart. 

(ii) You must submit an audit report 

of the audit findings, observations, deficiencies identified, and conclusions to 

BSEE within 60 days of the audit completion date. 

(2) If BSEE conducts the audit, BSEE 

will provide you with a report of the 

audit findings, observations, deficiencies identified, and conclusions as 

soon as practicable. 

(b) You must provide BSEE a copy of 

your CAP for addressing the deficiencies identified in the BSEE-directed audit within 60 days of the audit 

completion date. Your CAP must include the name and job title of the personnel responsible for correcting the 

identified deficiency(ies). The BSEE 

will notify you as soon as practicable 

after receipt of your CAP if your proposed schedule is not acceptable or if 

the CAP does not effectively address 

the audit findings. 

[78 FR 20442, Apr. 5, 2013] 

§ 250.1926 [Reserved] 

§ 250.1927 What happens if BSEE finds 

shortcomings in my SEMS program? 

If BSEE determines that your SEMS 

program is not in compliance with this 

subpart we may initiate one or more of 

the following enforcement actions: 

(a) Issue an Incident(s) of Noncompliance; 

(b) Assess civil penalties; or 

(c) Initiate probationary or disqualification procedures from serving as an 

OCS operator. 

§ 250.1928 What are my recordkeeping 

and documentation requirements? 

(a) Your SEMS program procedures 

must ensure that records and documents are maintained for a period of 6 

years, except as provided below. You 

must document and keep all SEMS audits for 6 years and make them available to BSEE upon request. You must 

maintain a copy of all SEMS program 

documents at an onshore location. 

(b) For JSAs, the person in charge of 

the job must document the results of 

the JSA in writing and must ensure 

that records are kept onsite for 30 

days. In the case of a MODU, records 

must be kept onsite for 30 days or until 

you release the MODU, whichever 

comes first. You must retain these 

records for 2 years and make them 

available to BSEE upon request. 

(c) You must document and date all 

management of change provisions as 

specified in §250.1912. You must retain 

these records for 2 years and make 

them available to BSEE upon request. 

(d) You must keep your injury/illness 

log for 2 years and make them available to BSEE upon request. 

(e) You must keep all evaluations 

completed on contractor’s safety policies and procedures for 2 years and 

make them available to BSEE upon request. 

(f) For SWA, you must document all 

training and reviews required by 

§250.1930(e). You must ensure that 

these records are kept onsite for 30 

days. In the case of a MODU, records 

must be kept onsite for 30 days or until 

you release the MODU, whichever 

comes first. You must retain these 

records for 2 years and make them 

available to BSEE upon request. 

(g) For EPP, you must document 

your employees’ participation in the 

development and implementation of 

the SEMS program. You must retain 

these records for 2 years and make 

them available to BSEE upon request. 

(h) You must keep all records in an 

orderly manner, readily identifiable, 

retrievable and legible, and include the 

date of any and all revisions. 

[76 FR 64462, Oct. 18, 2011, as amended at 78 

FR 20442, Apr. 5, 2013] 

§ 250.1929 What are my responsibilities 

for submitting OCS performance 

measure data? 

You must submit Form BSEE–0131 on 

an annual basis by March 31st. The 

form must be broken down quarterly, 

reporting the previous calendar year’s 

data. 


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§ 250.1930 30 CFR Ch. II (7–1–13 Edition) 

§ 250.1930 What must be included in 

my SEMS program for SWA? 

(a) Your SWA procedures must ensure the capability to immediately 

stop work that is creating imminent 

risk or danger. These procedures must 

grant all personnel the responsibility 

and authority, without fear of reprisal, 

to stop work or decline to perform an 

assigned task when an imminent risk 

or danger exists. Imminent risk or danger means any condition, activity, or 

practice in the workplace that could 

reasonably be expected to cause: 

(1) Death or serious physical harm; or 

(2) Significant environmental harm 

to: 

(i) Land; 

(ii) Air; or 

(iii) Mineral deposits, marine, coastal, or human environment. 

(b) The person in charge of the conducted work is responsible for ensuring 

the work is stopped in an orderly and 

safe manner. Individuals who receive a 

notification to stop work must comply 

with that direction immediately. 

(c) Work may be resumed when the 

individual on the facility with UWA determines that the imminent risk or 

danger does not exist or no longer exists. The decision to resume activities 

must be documented in writing as soon 

as practicable. 

(d) You must include SWA procedures 

and expectations as a standard statement in all JSAs. 

(e) You must conduct training on 

your SWA procedures as part of orientations for all new personnel who 

perform activities on the OCS. Additionally, the SWA procedures must be 

reviewed during all meetings focusing 

on safety on facilities subject to this 

subpart. 

[78 FR 20443, Apr. 5, 2013] 

§ 250.1931 What must be included in 

my SEMS program for UWA? 

(a) Your SEMS program must have a 

process to identify the individual with 

the UWA on your facility(ies). You 

must designate this individual taking 

into account all applicable USCG regulations that deal with designating a 

person in charge of an OCS facility. 

Your SEMS program must clearly define who is in charge at all times. In 

the event that multiple facilities, including a MODU, are attached and 

working together or in close proximity 

to one another to perform an OCS operation, your SEMS program must identify the individual with the UWA over 

the entire operation, including all facilities. 

(b) You must ensure that all personnel clearly know who has UWA and 

who is in charge of a specific operation 

or activity at all times, including when 

that responsibility shifts to a different 

individual. 

(c) The SEMS program must provide 

that if an emergency occurs that creates an imminent risk or danger to the 

health or safety of an individual, the 

public, or to the environment (as specified in §250.1930(a)), the individual with 

the UWA is authorized to pursue the 

most effective action necessary in that 

individual’s judgment for mitigating 

and abating the conditions or practices 

causing the emergency. 

[78 FR 20443, Apr. 5, 2013] 

§ 250.1932 What are my EPP requirements? 

(a) Your management must consult 

with their employees on the development, implementation, and modification of your SEMS program. 

(b) Your management must develop a 

written plan of action regarding how 

your appropriate employees, in both 

your offices and those working on offshore facilities, will participate in your 

SEMS program development and implementation. 

(c) Your management must ensure 

that employees have access to sections 

of your SEMS program that are relevant to their jobs. 

[78 FR 20443, Apr. 5, 2013] 

§ 250.1933 What procedures must be 

included for reporting unsafe working conditions? 

(a) Your SEMS program must include 

procedures for all personnel to report 

unsafe working conditions in accordance with §250.193. These procedures 

must take into account applicable 

USCG reporting requirements for unsafe working conditions. 

(b) You must post a notice at the 

place of employment in a visible location frequently visited by personnel 


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245 

Safety & Environmental Enforcement, Interior § 251.1 

that contains the reporting information in §250.193. 

[78 FR 20443, Apr. 5, 2013] 

PART 251—GEOLOGICAL AND 

GEOPHYSICAL (G&G) EXPLORATIONS OF THE OUTER CONTINENTAL SHELF 

Sec. 

251.1 Definitions. 

251.2 [Reserved] 

251.3 Authority and applicability of this 

part. 

251.4–251.6 [Reserved] 

251.7 Test drilling activities under a permit. 

251.8–251.14 [Reserved] 

251.15 Authority for information collection. 

AUTHORITY: 31 U.S.C. 9701, 43 U.S.C. 1334. 

SOURCE: 76 FR 64462, Oct. 18, 2011 unless 

otherwise noted. 

§ 251.1 Definitions. 

Terms used in this part have the following meaning: 

Act means the Outer Continental 

Shelf Lands Act (OCSLA), as amended 

(43 U.S.C. 1331 et seq.). 

Analyzed geological information means 

data collected under a permit or a lease 

that have been analyzed. Analysis may 

include, but is not limited to, identification of lithologic and fossil content, core analyses, laboratory analyses of physical and chemical properties, well logs or charts, results from 

formation fluid tests, and descriptions 

of hydrocarbon occurrences or hazardous conditions. 

Archaeological interest means capable 

of providing scientific or humanistic 

understanding of past human behavior, 

cultural adaptation, and related topics 

through the application of scientific or 

scholarly techniques, such as controlled observation, contextual measurements, controlled collection, analysis, interpretation, and explanation. 

Archaeological resources mean any material remains of human life or activities that are at least 50 years of age 

and of archaeological interest. 

Coastal environment means the physical, atmospheric, and biological components, conditions, and factors that 

interactively determine the productivity, state, condition, and quality of 

the terrestrial ecosystem from the 

shoreline inward to the boundaries of 

the coastal zone. 

Coastal Zone means the coastal 

waters (including the lands therein and 

thereunder) and the adjacent 

shorelands (including the waters therein and thereunder), strongly influenced 

by each other and in proximity to the 

shorelines of the several coastal States 

and extends seaward to the outer limit 

of the U.S. territorial sea. 

Coastal Zone Management Act means 

the Coastal Zone Management Act of 

1972, as amended (16 U.S.C. 1451 et seq.). 

Data means facts, statistics, measurements, or samples that have not 

been analyzed, processed, or interpreted. 

Deep stratigraphic test means drilling 

that involves the penetration into the 

sea bottom of more than 500 feet (152 

meters). 

Director means the Director of the 

Bureau of Safety and Environmental 

Enforcement, U.S. Department of the 

Interior, or a subordinate authorized to 

act on the Director’s behalf. 

Exploration means the commercial 

search for oil, gas, and sulphur. Activities classified as exploration include, 

but are not limited to: 

(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or 

other systems are used to detect or 

imply the presence of oil, gas, or sulphur; and 

(2) Any drilling, whether on or off a 

geological structure. 

Geological and geophysical scientific research means any oil, gas, or sulphur 

related investigation conducted in the 

OCS for scientific and/or research purposes. Geological, geophysical, and 

geochemical data and information 

gathered and analyzed are made available to the public for inspection and reproduction at the earliest practicable 

time. The term does not include commercial geological or geophysical exploration or research. 

Geological exploration means exploration that uses geological and geochemical techniques (e.g., coring and 

test drilling, well logging, and bottom 

sampling) to produce data and information on oil, gas, and sulphur resources 

in support of possible exploration and 


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