### 44 

## SUBCHAPTER B—OFFSHORE

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

Subpart A—General

A UTHORITY AND D EFINITION OF T ERMS

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.

P ERFORMANCE S TANDARDS

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?

F EES

250.125 Service fees. 250.126 Electronic payment instructions.

I NSPECTION OF O PERATIONS

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?

D ISQUALIFICATION

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

S PECIAL T YPES OF A PPROVALS

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?

N AMING AND I DENTIFYING F ACILITIES AND

W ELLS (D OES N OT I NCLUDE MODU S )

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]

S USPENSIONS

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 maythe Regional Supervisor order for a suspension?

P RIMARY L EASE R EQUIREMENTS , L EASE T ERM

E XTENSIONS

, AND L EASE C ANCELLATIONS

250.180 What am I required to do to keep my
lease term in effect?


### 45 Safety & Environmental Enforcement, Interior Pt. 250

250.181–250.185 [Reserved]

I NFORMATION AND R EPORTING R EQUIREMENTS

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 Isubmit 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 madeavailable to the public or for limited inspection.

R EFERENCES

250.198 Documents incorporated by reference.250.199 Paperwork Reduction Act statements—information collection.

Subpart B—Plans and Information

G ENERAL I NFORMATION

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?

P OST -A PPROVAL R EQUIREMENTS FOR THE EP, DPP, AND DOCD

250.282 Do I have to conduct post-approval monitoring?

D EEPWATER O PERATIONS P LANS (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

G ENERAL R EQUIREMENTS

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 measuresmust 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?

A PPLYING FOR A P ERMIT TO D RILL

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?

C ASING AND C EMENTING R EQUIREMENTS

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?


### 46 30 CFR Ch. II (7–1–13 Edition) Pt. 250

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?

D IVERTER S YSTEM R EQUIREMENTS

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?

B LOWOUT P REVENTER (BOP) S YSTEM R EQUIREMENTS

250.440 What are the general requirementsfor 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 relatedequipment must all BOP systems include?
250.444 What are the choke manifold requirements? 250.445 What are the requirements for kellyvalves, 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?

D RILLING F LUID R EQUIREMENTS

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?

O THER D RILLING R EQUIREMENTS

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?

A PPLYING FOR A P ERMIT T O M ODIFY AND W ELL R ECORDS

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?

H YDROGEN S ULFIDE

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.

C ASING P RESSURE M ANAGEMENT

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?


### 47 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 preventionequipment 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

G ENERAL R EQUIREMENTS FOR P LATFORMS

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?

P LATFORM A PPROVAL P ROGRAM

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?

P LATFORM V ERIFICATION P ROGRAM

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?

I NSPECTION , M AINTENANCE

, AND A SSESSMENT

OF P LATFORMS

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.


### 48 30 CFR Ch. II (7–1–13 Edition) Pt. 250

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

G ENERAL

250.1150 What are the general reservoir production requirements?

W ELL T ESTS AND S URVEYS

250.1151 How often must I conduct well production tests?
250.1152 How do I conduct well tests? 250.1153 [Reserved]

C LASSIFYING R ESERVOIRS

250.1154–250.1155 [Reserved]

A PPROVALS P RIOR TO P RODUCTION

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?

P RODUCTION R ATES

250.1159 May the Regional Supervisor limit my well or reservoir production rates?

LARING , V ENTING

, AND B URNING H YDROCARBONS

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 H 2 S?

O THER R EQUIREMENTS

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

O UTER C ONTINENTAL S HELF L ANDS A CT C IVIL P ENALTIES

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?


### 49 Safety & Environmental Enforcement, Interior Pt. 250

F EDERAL O IL AND G AS R OYALTY M ANAGEMENT A CT C IVIL P ENALTIES D EFINITIONS

250.1450 What definitions apply to this subpart?

P ENALTIES A FTER A P ERIOD T O C ORRECT

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?

P ENALTIES W ITHOUT A P ERIOD T O C ORRECT

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 therecord 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?

G ENERAL P ROVISIONS

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?

C RIMINAL P ENALTIES

250.1480 May the United States criminallyprosecute me for violations under Federal oil and gas leases?

B ONDING R EQUIREMENTS

250.1490 What standards must my BOEMspecified surety instrument meet? 250.1491 How will BOEM determine theamount of my bond or other surety instrument?

F INANCIAL S OLVENCY R EQUIREMENTS

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 trainingprogram 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.


### 50 30 CFR Ch. II (7–1–13 Edition) Pt. 250

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

G ENERAL

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?

P ERMANENTLY P LUGGING W ELLS

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? T EMPORARY A BANDONED W ELLS

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 longernecessary to maintain a well in temporary abandoned status?

R EMOVING P LATFORMS AND O THER F ACILITIES

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 inmy 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 otherfacility, 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?

S ITE C LEARANCE FOR W ELLS , P LATFORMS

, AND O THER F ACILITIES

250.1740 How must I verify that the site of apermanently 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?

P IPELINE D ECOMMISSIONING

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]


### 51 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 documentedin 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?

A UTHORITY : 30 U.S.C. 1751, 31 U.S.C. 9701, 43
U.S.C. 1334.

S OURCE : 76 FR 64462, Oct. 18, 2011, unless
otherwise noted.

E DITORIAL N OTE : Nomenclature changes to part 250 appear at 77 FR 50891, Aug. 22, 2012. 

### Subpart A—General

A UTHORITY AND D EFINITION OF T ERMS

§ 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 theSecretary’s authority, the Director requires that all operations:

(a) Be conducted according to theOCS Lands Act (OCSLA), the regulations in this part, BSEE orders, thelease or right-of-way, and other applicable laws, regulations, and amendments; and

(b) Conform to sound conservationpractice 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 thehuman, 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 programthat govern oil, gas, and sulphur exploration, development, and productionoperations on the OCS. When you conduct operations on the OCS, you mustsubmit 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.

T ABLE —W HERE T O F IND I NFORMATION FOR C ONDUCTING O PERATIONS

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.


### 52 30 CFR Ch. II (7–1–13 Edition) § 250.103

T ABLE —W HERE T O F IND I NFORMATION FOR C ONDUCTING O PERATIONS —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 Lesseesand Operators (NTLs) that clarify, supplement, or provide more detail about certain requirements. NTLs may alsooutline 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 themeanings 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 otheractivity 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 theportion 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 receiveoil for processing, refining, or transshipment that was extracted from the OCS and transported directly to suchState 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 seriousdamage, due to factors such as prevailing winds and currents to the marine or coastal environment in theevent 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, undersection 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 mayinclude, but is not limited to, identification of lithologic and fossil content, core analysis, laboratory analyses of physical and chemical properties,


### 53 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 ofOcean 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 orscholarly techniques, such as controlled observation, contextual measurement, controlled collection, analysis, interpretation, and explanation.

Archaeological resource means anymaterial 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 anyprimary or secondary ambient air quality standards established by EPA.

Best available and safest technology (BAST) means the best available andsafest technologies that the BSEE Director determines to be economically feasible wherever failure of equipmentwould have a significant effect on safety, health, or the environment.

Best available control technology (BACT) means an emission limitationbased 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 thatinteractively 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 controlshorelands, the uses of which have a direct and significant impact on thecoastal waters, and the inward boundaries of which may be identified by theseveral 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 moreproducible or producing well completions on each of two or more leases or portions of leases, with different leaseoperating 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 havenot been analyzed, processed, or interpreted.

Departures mean approvals grantedby 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; properlydevelop a lease; conserve natural resources, or protect life, property, orthe marine, coastal, or human environment.

Development means those activities that take place following discovery ofminerals 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


### 54 30 CFR Ch. II (7–1–13 Edition) § 250.105

for the purpose of producing the minerals discovered.

Development geological and geophysical (G&G) activities mean those G&G and related data-gathering activities onyour 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 responsibilityfor 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, eitheronshore or offshore, other than the facility or facilities covered by the proposed Exploration Plan (EP) or Development and Production Plan (DPP).

Enhanced recovery operations meanpressure 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 CFR550.303, means an OCS facility described in an Exploration Plan or a Development and Production Plan approved before June 2, 1980.

Exploration means the commercialsearch 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 commercialquantities of oil, gas, and sulphur, including the drilling of any additional well needed to delineate any reservoir
to enable the lessee to decide whetherto 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, gasor 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 forproduct measurement and royalty determination (e.g., lease Automatic Custody Transfer Units, gas meters) of OCS production on installations not onthe OCS. Any group of OCS installations interconnected with walkways, orany group of installations that includes a central or primary installation with processing equipment andone or more satellite or secondary installations is a single facility. The Regional Supervisor may decide that thecomplexity of the individual installations justifies their classification as separate facilities.

(2) As used in 30 CFR 550.303, meansall installations or devices permanently or temporarily attached to the seabed. They include mobile offshoredrilling 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 forexploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or moresources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating


### 55 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 avessel, a structure, or an artificial island used for drilling, well completion,well-workover, or production operations.

(4) As used in §§250.900 through250.921, means all installations or devices permanently or temporarily attached to the seabed. They are used forexploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or moresources. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floatingproduction, 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 theOCS. Facilities also include DOI-regulated pipelines.

Flaring means the burning of naturalgas 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 othersystems to detect or imply the presence of oil, gas, or sulphur in commercial quantities.

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

H

2 S absent means: (1) Drilling, logging, coring, testing,or producing operations have confirmed the absence of H 2 S in concentrations that could potentially result in atmospheric concentrations of 20 ppm
or more of H 2 S; or

(2) Drilling in the surrounding areasand correlation of geological and seismic data with equivalent stratigraphic
units have confirmed an absence of H 2 S throughout the area to be drilled.

H

2 S present means drilling, logging,coring, testing, or producing operations have confirmed the presence of
H 2 S in concentrations and volumesthat could potentially result in atmospheric concentrations of 20 ppm or
more of H 2 S.

H

2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H 2 S
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


### 56 30 CFR Ch. II (7–1–13 Edition) § 250.105

under section 6 of the Act and that authorizes exploration for, and development and production of, minerals. The term also means the area covered bythat 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 termlessee 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 significantimpact on the quality of the human environment requiring preparation of an environmental impact statement undersection 102(2)(C) of the National Environmental Policy Act).

Marine environment means the physical, atmospheric, and biological components, conditions, and factors thatinteractively determine the productivity, state, condition, and quality of the marine ecosystem. These includethe waters of the high seas, the contiguous zone, transitional and intertidalareas, 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 dailyrate 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 mineralsthat 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 ofEPA 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 isnot 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 capmeans 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 explorefor, develop, and produce leased substances.

Operator means the person the lessee(s) designates as having control or management of operations on theleased 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 ofoperating 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


### 57 Safety & Environmental Enforcement, Interior § 250.105

private, public, or municipal corporation.

Pipelines are the piping, risers, andappurtenances installed for transporting oil, gas, sulphur, and produced
waters.

Processed geological or geophysical information means data collected under apermit 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 knownperturbing causes, rearranging or filtering data, and combining or transforming data elements. Reprocessing is the additional processing other than ordinary processing used in the generalcourse 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 successfulcompletion of any means for the removal of minerals, including such removal, field operations, transfer ofminerals to shore, operation monitoring, maintenance, and workover operations.

Production areas are those areaswhere flammable petroleum gas, volatile liquids or sulphur are produced, processed (e.g., compressed), stored, transferred (e.g., pumped), or otherwisehandled before entering the transportation process.

Projected emissions mean emissions, either controlled or uncontrolled, from

a source or sources.

Prospect means a geologic featurehaving the potential for mineral deposits.

Regional Director means the BSEE officer with responsibility and authority for a Region within BSEE.

Regional Supervisor means the BSEEofficer with responsibility and authority for operations or other designatedprogram 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 valvesthat 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;


### 58 30 CFR Ch. II (7–1–13 Edition) § 250.106

(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 initialwell-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 Statelessee granted a right-of-use and easement.

[76 FR 64462, Oct. 18, 2011, as amended at 78 FR 20439, Apr. 5, 2013]

P ERFORMANCE S TANDARDS

§ 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, otherinterested parties, and relevant Federal agencies.

§ 250.107 What must I do to protecthealth, 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 availableand 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 Ifollow 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 requirementsof American Petroleum Institute Specification for Offshore Pedestal Mounted


### 59 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 acrane 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 recordsmust 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 ofthe crane operator and all rigger personnel for at least 4 years. The recordsmust be kept at the OCS fixed platform.

(f) You must operate and maintain all other material-handling equipmentin 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 weldinguntil 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 thewelding 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 moveany 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 whereslag, sparks, or other burning materials could fall. If moving this equipment is impractical, you must protect that equipment with flame-proofedcovers, 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.


### 60 30 CFR Ch. II (7–1–13 Edition) § 250.114

(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 incharge 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 RP505, 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 expertisein area classification and the performance, operation and hazards of electrical equipment.

(c) You must install all electricalsystems 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 anignition 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 notresult 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:


### 61 Safety & Environmental Enforcement, Interior § 250.125

(1) Enhance recovery; (2) Prevent flaring of casinghead gas;

or

(3) Implement other conservationmeasures 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 CFR550.119, 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 orstored 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 rockof 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.

F EES

§ 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 F EDERAL R EGISTER . If a significant adjustment is needed to arrive at the new actual cost for anyreason other than inflation, then a proposed rule containing the new fees will be published in the F EDERAL R EGISTER 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 ..................................... § 250.2 92(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).


### 62 30 CFR Ch. II (7–1–13 Edition) § 250.125

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 apiece of equipment or ancillary system that is protected by one or more of the safety devices required by API RP14C (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 ........................................ § 2 50.1008(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 ........................................ § 250.1 018(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 inparagraph (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 feewhen you submit the amended application. (c) Verbal approvals are occasionallygiven 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]


### 63 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 applicationthrough 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.

I NSPECTIONS OF O PERATIONS

§ 250.130 Why does BSEE conduct inspections?

BSEE will inspect OCS facilities and any vessels engaged in drilling or otherdownhole 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 reimburseyou 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.

D ISQUALIFICATION

§ 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, whomay 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 beforemaking a determination that your operating performance is unacceptable.

§ 250.136 How will BSEE determine ifmy 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.


### 64 30 CFR Ch. II (7–1–13 Edition) § 250.140

S PECIAL T YPES OF A PPROVALS

§ 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 theRegional 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 usemust 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’swritten approval before you can use alternate procedures or equipment.

(c) To receive approval, you must either submit information or give an oralpresentation to the appropriate Regional Supervisor. Your presentationmust 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 theDistrict 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 operatormay designate for the Regional Supervisor’s approval, or the Regional Director may require you to designate anagent empowered to fulfill your obligations under the Act, the lease, or the regulations in this part.

(b) You or your designated operatormay 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 30CFR 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 30CFR 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 hasbeen designated), and the person actually performing the activity to which the requirement applies are jointly and severally responsible for complying with the regulation.


### 65 Safety & Environmental Enforcement, Interior § 250.154

N AMING AND I DENTIFYING F ACILITIES

AND W ELLS (D OES N OT I NCLUDE MODU S )

§ 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 bethe 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 benamed 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 thewell. 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 facilitiesare 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, thenthe 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 andthe 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.


### 66 30 CFR Ch. II (7–1–13 Edition) §§ 250.160–250.167

(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 wellat 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]

S USPENSIONS

§ 250.168 May operations or production be suspended?

(a) You may request approval of a suspension, or the Regional Supervisormay direct a suspension (Directed Suspension), for all or any part of a lease
or unit area.

(b) Depending on the nature of thesuspended 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 thelength 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 forup to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the conditions
of the individual case involved. BSEEmay 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 Supervisorwill 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., endof 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 workleading 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 withjudicial 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;


### 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 otheraquatic 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 operationsthat 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 allowyou time to begin drilling or other operations when you are prevented by reasons beyond your control, such asunexpected 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 aprimary term of 8 years with a requirement to drill within 5 years;

(2) Before the end of the third year ofthe primary term, you or your predecessor in interest must have acquiredand 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 withidentification 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 conductingadditional data processing or interpretation of the geophysical informationwith 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 maygrant 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 ofthe primary term, you or your predecessor in interest must have acquired


### 68 30 CFR Ch. II (7–1–13 Edition) § 250.176

and interpreted geophysical information that:

(i) Indicates that all or a portion of apotential 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 conductingadditional data processing or interpretation of the geophysical informationwith 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 newgeophysical 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 inparagraphs (c)(2) and (c)(3) of this section; or

(iii) Drill a well below 25,000 feet TVDSS 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 thecause of the hazard, the potential damage, and the available mitigation

measures.

(3) You must pay for the study unlessyou 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 ExplorationPlan (including any required mitigating measures);

(c) Submit a revised Developmentand Production Plan (including any required mitigating measures); or

(d) Submit a revised DevelopmentOperations Coordination Document according to 30 CFR part 550, subpart B.

P RIMARY L EASE R EQUIREMENTS , L EASE

T ERM E XTENSIONS

, AND L EASE C AN

CELLATIONS

§ 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 theDistrict 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 ofits primary term unless you are conducting operations on your lease (see 30CFR 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 toestablish production in paying quantities on the lease.

(b) If you stop conducting operationsduring the last 180 days of your primary lease term, your lease will expire unless you either resume operations orreceive an SOO or an SOP from the Regional Supervisor under §250.172, §250.173, §250.174, or §250.175 before the


### 69 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 ofthe 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 expireunless 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 theend of the 180th day after you stop operations.

(e) You may ask the Regional Supervisor to allow you more than 180 daysto 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 additionaltime, the Regional Supervisor must determine that the longer period is in theNational interest, and it conserves resources, prevents waste, or protects correlative rights.

(f) When you begin conducting operations on a lease that has continuedbeyond its primary term, you must immediately notify the District Manager either orally or by fax or e-mail andfollow 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 thissection 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 andcompleting the leaseholding operations.

(j) For leases continued beyond the primary term, you must immediatelyreport to the District Manager if operations do not begin before the end of the 180-day period.

§§ 250.181–250.185 [Reserved]

I NFORMATION AND R EPORTING R EQUIREMENTS

§ 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 formidentical 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 whenthe Region/District is equipped to accept it.

(b) When BSEE specifies, you mustinclude, 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


### 70 30 CFR Ch. II (7–1–13 Edition) § 250.187

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

(c) Nothing in this subpart relievesyou 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 orother 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 froma failure of surface equipment or procedures.

(4) All fires and explosions.(5) All reportable releases of hydrogen sulfide (H 2 S) 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 enoughso that operations on the facility cannot continue until repairs are made.

(8) All incidents involving crane orpersonnel/material handling operations.

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

(b) You must provide a written reportof 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 forincidents requiring immediate notification.

For an incident requiring immediate notification under §250.188(a), you must notify the District Manager via oralcommunication immediately after aiding the injured and stabilizing the situation. Your oral communication must provide the following information:

(a) Date and time of occurrence;


### 71 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 forincidents 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. Thereport 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 ofthe written report required by paragraph (a) of this section, provided thereport 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. Thepurpose of the investigation is to prepare a public report that determines
the cause or causes of the incident. Theinvestigation 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 statisticsmust I submit relating to a hurricane, earthquake, or other natural occurrence?

(a) You must submit evacuation statistics to the Regional Supervisor for anatural occurrence, such as a hurricane, a tropical storm, or an earthquake. Statistics include facilities andrigs 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


### 72 30 CFR Ch. II (7–1–13 Edition) § 250.193

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 mustuse Form BSEE–0143, Facility/Equipment Damage Report, to make this andall 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 assessthe extent of the damage (major, medium, minor); and

(iii) Estimate the time it will take toreplace or repair each damaged structure and piece of equipment and return
it to service. The initial estimate neednot 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 reportsmonthly 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 BSEEany 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 tosafety 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 apossible violation, or when a BSEE employee detects a possible violation, BSEE will investigate according to BSEE procedures and notify any otherFederal 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 toinvestigate 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 unsafeworking 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


### 73 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 operationswithin 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 appropriateBSEE 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 thecosts of processing geophysical information (that does not include cost of data acquisition):

(1) If, at the request of the RegionalDirector, 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 toyou before October 1, 1985, and the Regional Director requests and retains
the information.

(c) When you request reimbursement, you must identify reproduction andprocessing 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 thepublic 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 ofthe 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:


### 74 30 CFR Ch. II (7–1–13 Edition) § 250.197

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) ofthis section, whichever is earlier. However, items 33 through 38 will not bereleased 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, Geologicaldata 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, Geologicaldata, 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 than60 days if the Regional Supervisor determines it is needed by affected States
to make decisions under 30 CFR 550, subpart B. TheRegional 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, Geologicaldata, 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 notapply. The release time applies to the geophysical data and information only if acquired postlease for a
lessee’s exclusive use.


### 75 Safety & Environmental Enforcement, Interior § 250.198

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

(4) Your lease is still in effect, Geophysical data, Processedgeophysical 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 notapply. 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 thistable 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 notbeen 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 part551 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, processedand interpreted G&G information, Geological data and information: 10 years after BOEMissues the permit; Geophysical data: 50 yearsafter 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, andwho 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.

R EFERENCES

§ 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 thepublishing organization of the documents, the address and phone numberwhere you may obtain these documents, and the documents incorporatedby reference. The Director of the Federal Register has approved the


### 76 30 CFR Ch. II (7–1–13 Edition) § 250.198

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 F EDERAL R EGISTER and amend this section.

(2) The BSEE may make the ruleamending the document effective without prior opportunity for public comment when BSEE determines:

(i) That the revisions to a documentresult 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 inthis 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 compliancewith specific portions of the listed documents. In each instance, the applicable document is the specific edition orspecific edition and supplement or addendum cited in this section.

(c) Under §§250.141 and 250.142, you may comply with a later edition of aspecific document incorporated by reference, provided:

(1) You show that complying with thelater 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 documentsat 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/federal

l register/code

l of

l

federal

l regulations/ibr

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

(2) ACI 318R–95, Commentary onBuilding 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, Specificationfor 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 PressureVessel 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;


### 77 Safety & Environmental Enforcement, Interior § 250.198

(2) ANSI/ASME Boiler and PressureVessel Code, Section IV, Rules for Construction of Heating Boilers; includingAppendices 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 forConstruction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; July 1, 2005Addenda, 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, PipeFlanges 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 EquipmentUsed 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, InterimGuidance 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 inthe 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—TankGauging, 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—TankGauging, Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks byAutomatic 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, reaffirmedNovember 2005; incorporated by reference at §250.1202;

(13) API MPMS, Chapter 4—Proving Systems, Section 5—Master-Meter


### 78 30 CFR Ch. II (7–1–13 Edition) § 250.198

Provers, Second Edition, May 2000, reaffirmed: August 2005; incorporated by reference at §250.1202;

(14) API MPMS, Chapter 4—ProvingSystems, 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 StandardTest Measures, Second Edition, December 1998; reaffirmed 2003; incorporated by reference at §250.1202;

(16) API MPMS, Chapter 5—Metering,
Section 1—General Considerations forMeasurement 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 forLiquid 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—MeteringAssemblies, 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—MeteringAssemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991; reaffirmed, February 2007; incorporated by reference at §250.1202;

(23) API MPMS, Chapter 6—MeteringAssemblies, 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 forManual 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 forAutomatic 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—StandardTest Method for Density, Relative Density (Specific Gravity), or API Gravityof 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,


### 79 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 Standard2540, 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, ThirdEdition, 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 GrossHeating 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—Section1—Allocation Measurement, First Edition, September 1993; reaffirmed October 2006; incorporated by reference at §250.1202;

(46) API MPMS, Chapter 21—FlowMeasurement Using Electronic Metering Systems, Section 1—Electronic Gas Measurement, First Edition, August1993; reaffirmed, July 2005; incorporated by reference at §250.1203;

(47) API RP 2A–WSD, Recommended Practice for Planning, Designing andConstructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000; Errataand 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;


### 80 30 CFR Ch. II (7–1–13 Edition) § 250.198

(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, RecommendedPractice 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 Analysisof 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, RecommendedPractice 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 valvesystems—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 SafetySystems 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 Systemsfor 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 Analysisfor 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, ThirdEdition, 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 FlowZones 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, Division1 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;


### 81 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, August1993; reaffirmed November 2003; incorporated by reference at §250.1202;

(68) ANSI/API Spec. Q1, Specificationfor Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007 (Identical), Petroleum, petrochemical and naturalgas 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 SafetyValves for Offshore Service, First Edition, February 1, 1996; reaffirmed January 2003; incorporated by reference at §250.806;

(72) ANSI/API Spec. 6D, Specificationfor 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; alsoavailable as ISO 10432:2004; incorporated by reference at §250.806;

(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, ThirdEdition, July 2008; Effective Date: January 1, 2009, Contains API MonogramAnnex 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 forLiquid 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 DuringWell 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) Chapter4—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—Measurementof Liquid Hydrocarbons by Coriolis Meters; First Edition, reaffirmed March 2008; incorporated by reference at §250.1202(a)(2) and (3);


### 82 30 CFR Ch. II (7–1–13 Edition) § 250.198

(82) API Manual of Petroleum Measurement Standards (MPMS) Chapter 5—Metering, Section 8—Measurement of Liquid Hydrocarbons by UltrasonicFlow 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 GeneralizedCrude Oils, Refined Products, and Lubricating Oils; May 2004, (incorporatingAddendum 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) Chapter12—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) Chapter12—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 theWaterdraw 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) Chapter21—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—FlowMeasurement Using Electronic Metering Systems, Addendum to Section 2— Flow Measurement Using Electronic Metering Systems, Inferred Mass; FirstEdition, 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, approvedDecember 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 forPortland Cement; incorporated by reference at §250.901;

(4) ASTM Standard C 330–05, approvedDecember 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 Specificationfor 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 forUnderwater 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, RevisedJanuary 17, 2003; incorporated by reference at §§250.901 and 250.490;


### 83 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—Measurementof 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 forStandardization (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; Correctedversion 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 SEMSAuditing 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 thesubpart 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, andsulphur 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 abenefit 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 Parts251, 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 orsponsor, 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 suggestionsfor reducing the burden, to the Information Collection Clearance Officer, Bureau of Safety and EnvironmentalEnforcement, 381 Elden Street, Herndon, VA 20170.

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


### 84 30 CFR Ch. II (7–1–13 Edition) § 250.199

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, aresafe and protect the environment, and result in diligent exploration, development, and production on OCS leases. Tosupport 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 withstatutory 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 usedin 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 thatproduction 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 ensurethat 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 ensu re 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 Pape rwork 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 aretechnically 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 operationsare safe; protect the human, marine, and coastal environment; and will result in diligent exploration, development, and production of sulphur leases.


### 85 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 siteclearance 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 tosafety and the environment, as well as policies and procedures to assure safety and environmental protection whileconducting 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

G ENERAL I NFORMATION

§ 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 maketo 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 previouslyunder the anticipated operating conditions; or

(3) Have operating characteristicsthat 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, floatingproduction, 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, typeof 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)).


### 86 30 CFR Ch. II (7–1–13 Edition) § 250.201

§ 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 anywater 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 RegionalSupervisor determines that it is necessary to evaluate your proposed plan
or document.

(c) Limiting information. The RegionalDirector 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 orrequired 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 youpreviously 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 arenecessary to protect the Federal government from loss due to production on other leases or units or from adjacent lands under the jurisdiction of otherentities (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-bearingzone 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 ordrain an adjacent property, the Regional Supervisor may require special measures to protect the rights of theFederal government and objecting lessees or operators of adjacent leases or
units.

P OST -A PPROVAL R EQUIREMENTS 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


### 87 Safety & Environmental Enforcement, Interior § 250.292

or derived from your monitoring programs. The Regional Supervisor will specify requirements for preparing and submitting these reports.

D EEPWATER O PERATIONS P LAN (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 completiontechnology, from a total system approach. The DWOP does not replace,but supplements other submittals required by the regulations such as BOEM Exploration Plans, Developmentand Production Plans, and Development Operations Coordination Documents. BSEE will use the information in your DWOP to determine whetherthe 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 (oftencalled 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 thanthe 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 ofthe typical wellbore, casing, and completion;

(b) Structural design, fabrication,
and installation information for eachsurface 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;


### 88 30 CFR Ch. II (7–1–13 Edition) § 250.293

(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 offtakesystem for transferring produced hydrocarbons to a transport vessel;

(i) Information about subsea wells and associated systems that constituteall 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) ofthe 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 tablesummarizing 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 inyour 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 lesseeshall take measures to prevent unauthorized discharge of pollutants into
the offshore waters. The lessee shallnot 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 andremoval 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 tomodification 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 shallnot relieve the lessee of any responsibility provided for by law.


### 89 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 Managermay also restrict the use of components which could cause unreasonabledegradation 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 toprevent 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 aproperly 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 asprocessing devices to treat or skim liquids but may be used to collect treated-produced water, treated-produced sand, or liquids from drip pans anddeck 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 intooffshore 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 thatthey 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 durableenough 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, asappropriate, 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

G ENERAL R EQUIREMENTS

§ 250.400 Who is subject to the requirements of this subpart?

The requirements of this subpartapply to lessees, operating rights owners, operators, and their contractors
and subcontractors.


### 90 30 CFR Ch. II (7–1–13 Edition) § 250.401

§ 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 untilthe 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 andmaterials 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 ofall 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 DistrictManager 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 operationand 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 downthe diesel engine in the event of a runaway.

(a) For a diesel engine that is not continuously manned, you must equipthe engine with an automatic shutdown device;

(b) For a diesel engine that is continuously manned, you may equip theengine 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;


### 91 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 drillingoperations 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 todetermine 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 proceduresor equipment during drilling operations after receiving approval fromthe 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 approvedepartures from the drilling requirements specified in this subpart. You may apply for a departure from drilling requirements by writing to the DistrictManager. You should identify and discuss the departure you are requesting in your APD (see §250.414(h)).

A PPLYING FOR A P ERMIT T O D RILL

§ 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), Developmentand 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 FormBSEE–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 andBSEE–0123S, you must include the information described in the following
table.


### 92 30 CFR Ch. II (7–1–13 Edition) § 250.412

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 UniversalTransverse 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 methodused for this conversion, since the various methods may produce different
values.

§ 250.413 What must my description ofwell 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 andits related wellhead equipment. In calculating maximum anticipated surface pressures, you must consider: drilling, completion, and producing conditions; drilling fluid densities to be used belowvarious 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 greaterdegree 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).


### 93 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 thawsubsidence and freezeback effect, proper anchorage, and well control;

(e) A statement of how you evaluated the best practices included in API RP65, Recommended Practice for Cementing Shallow Water Flow Zones in DeepWater 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, IsolatingPotential 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-partyverification 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 surfacepressure. The documentation must include actual shearing and subsequent pressure integrity test results for themost rigid pipe to be used and calculations of shearing capacity of all pipe tobe used in the well, including correction for MASP;

(f) When you use a subsea BOP stackor 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 registeredprofessional engineer capable of providing the verifications required under this part.


### 94 30 CFR Ch. II (7–1–13 Edition) § 250.417

(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 toperform the verification in the appropriate jurisdiction, and evidence todemonstrate 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 thelocation to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearingram 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 mustprovide information and data to demonstrate the drilling unit’s capabilityto perform at the proposed drilling location. This information must includethe 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 yousubmit your APD, the District Manager may approve your APD but require you to collect and report this information during operations. Underthis circumstance, the District Manager has the right to revoke the approval of the APD if information collected during operations show that thedrilling unit is not capable of performing at the proposed location.

(b) Foundation requirements. You mustprovide 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 toBOEM, 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 thatthe 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 beenproven 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 contingencyplan that addresses design and operating limitations of the drilling unit. Your plan must identify the actionsnecessary to maintain safety and prevent damage to the environment. Actions must include the suspension, curtailment, or modification of drilling orrig operations to remedy various operational or environmental situations (e.g., vessel motion, riser offset, anchortensions, wind speed, wave height, currents, icing or ice-loading, settling, tiltor 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. Youmust also provide current documentation of any operational limitations imposed by an appropriate classification society.

(e) Floating drilling unit. If you use afloating drilling unit, you must indicate that you have a contingency planfor 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.


### 95 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 drillingequipment, BOP systems and components, diverter systems, and other associated equipment and materials aresuitable 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]

C ASING AND C EMENTING R EQUIREMENTS

§ 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 thatthe casing and cementing design is appropriate for the purpose for which it isintended 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) towithstand the anticipated stresses imposed by tensile, compressive, andbuckling loads; burst and collapse pressures; thermal effects; and combinations thereof.

(2) The casing design must includesafety measures that ensure well control during drilling and safe operations during the life of the well.

(3) On all wells that use subsea BOPstacks, 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 finalstring), 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 BSEEDistrict 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


### 96 30 CFR Ch. II (7–1–13 Edition) § 250.421

times ensure that the cement placedbehind the bottom 500 feet of casing attains a minimum compressive strengthof 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, thecasing 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 minimumdepth 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 onanticipated or encountered geologic characteristics or wellbore conditions. Use enough cement to cover and isolate all hydrocarbon-bearing zones and isolate abnormalpressure 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 onanticipated 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 shoeand 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 theliner at least 100 feet above the previous casing shoe. Same as cementing requirements for specificcasing 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 8hours. 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


### 97 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 offormation conditions, cement composition, effects of nippling down, presenceof potential drilling hazards, well conditions during drilling, cementing, andpost 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 operationsuntil 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 testmust 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 asuccessful 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 immediatelyinvestigate 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]


### 98 30 CFR Ch. II (7–1–13 Edition) § 250.424

§ 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. Ifthe pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you mustre-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 orliners. 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 testto 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 wellkicks to adjust the drilling fluid program and the setting depth of the next casing string. You must record all test
results and hole-behavior observationsmade 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.


### 99 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]

D IVERTER S YSTEM R EQUIREMENTS

§ 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 arrangedto 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 discussedthe departure in your APD and received approval from the District Manager.


### 100 30 CFR Ch. II (7–1–13 Edition) § 250.433

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 leastonce every 24-hour period after the initial test. After you have nippled up onconductor 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 operationswith 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 recordkeepingrequirements for diverter actuations and tests?

You must record the time, date, and
results of all diverter actuations andtests 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.

B LOWOUT P REVENTER (BOP) S YSTEM R EQUIREMENTS

§ 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 BOPsystem 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 surfacecasing. 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 accumulatorsystem that provides 1.5 times the volume of fluid capacity necessary toclose 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


### 101 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 equipmentrequired by the regulations in this subpart.

§ 250.442 What are the requirements for a subsea BOP system?

When you drill with a subsea BOPsystem, you must install the BOP system before drilling below the surfacecasing. 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 theneed. 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 RP53, 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 designedto 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 hydraulicsupply 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 controlsystem, 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 foroperating 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 othersuitable precautions to compensate for the reduction in pressure and to maintain a safe and controlled well condition.


### 102 30 CFR Ch. II (7–1–13 Edition) § 250.443

[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 thefollowing 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 themaximum 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 theanticipated 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 pressureof the ram BOPs. If your choke manifold has buffer tanks downstream ofchoke 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


### 103 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 forDrilling Wells (incorporated by reference as specified in §250.198). Youmust 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 17.12and 18.12, Quality Management, described in API RP 53, record the resultsof 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 recordsare 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 seaconditions 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 BOPsystem (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 theconclusion 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 BOPcomponent. You must conduct the lowpressure test before the high-pressure test. Each individual pressure test must hold pressure long enough todemonstrate 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 greaterthan 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 workingpressure 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


### 104 30 CFR Ch. II (7–1–13 Edition) § 250.449

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 mayuse 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 orrepair 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 arefunction 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 theseafloor 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 howthe 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


### 105 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 forannular 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., befor e 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 i s 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-sizedrill 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 ratedworking 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]

D RILLING F LUID R EQUIREMENTS

§ 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 holewith 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.


### 106 30 CFR Ch. II (7–1–13 Edition) § 250.457

(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 annuluswith drilling fluid before the hydrostatic pressure decreases by 75 psi, orevery 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 circulateand 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 casingstring. 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 ratedworking 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 anddegasser 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 toindustry-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 toan 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


### 107 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 pumpdischarge 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 materialsand 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 perminute, per square foot of area, whichever is greater. In addition:

(1) If natural means provide adequateventilation, then a mechanical ventilation system is not necessary;

(2) If a mechanical system does notrun continuously, then it must activate when gas detectors indicate thepresence 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 drillingfluid-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 accessto the area, automatic door-closing devices, air locks, or other devices approved by the District Manager;

(b) Gas detectors and alarms exceptin 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 pressurizedelectrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you
must locate the air intake outside ofand as far as practicable from hazardous areas; and

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


### 108 30 CFR Ch. II (7–1–13 Edition) § 250.460

O THER D RILLING R EQUIREMENTS

§ 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 requirementsfor 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. Surveysmust 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-drillingtechnology 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 totaldepth. 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 ofthe well’s directional survey to the affected leaseholder. This could occurwhen 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 andestablish 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 activitythat minimizes the risk to drilling operations. The timing of your drillsmust cover a range of different operations, including drilling with a diverter, on-bottom drilling, and tripping.


### 109 Safety & Environmental Enforcement, Interior § 250.466

(c) Recordkeeping requirements. Foreach 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 requireyou 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 informationshows 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.

A PPLYING FOR A P ERMIT T O M ODIFY AND W ELL R ECORDS

§ 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 (formBSEE–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 Managerbefore 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 ofthe 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 whiledrilling 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;


### 110 30 CFR Ch. II (7–1–13 Edition) § 250.467

(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 willprovide 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.

H YDROGEN S ULFIDE

§ 250.490 Hydrogen sulfide.

(a) What precautions must I take when operating in an H 2 S area? You must: (1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H 2 S and to mitigate damage to property and the environment caused by H 2 S. You must follow the requirements of this section when conducting drilling, well-completion/well-workover, and production operations in zones with
H 2 S present and when conducting operations in zones where the presence of
H 2 S is unknown. You do not need tofollow these requirements when operating in zones where the absence of H 2 S 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.

H

2 S absent means: (1) Drilling, logging, coring, testing,or producing operations have confirmed the absence of H 2 S in concentrations that could potentially result in


### 111 Safety & Environmental Enforcement, Interior § 250.490

atmospheric concentrations of 20 ppm
or more of H 2 S; or

(2) Drilling in the surrounding areasand correlation of geological and seismic data with equivalent stratigraphic
units have confirmed an absence of H 2 S throughout the area to be drilled.

H

2 S present means that drilling, logging, coring, testing, or producing operations have confirmed the presence
of H 2 S in concentrations and volumesthat could potentially result in atmospheric concentrations of 20 ppm or
more of H 2 S.

H

2 S unknown means the designation of a zone or geologic formation where neither the presence nor absence of H 2 S
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 H 2 S. You must: (1) Request and obtain an approved
classification for the area from the Regional Supervisor before you begin operations. Classifications are ‘‘H 2 S absent,’’ H 2 S present,’’ or ‘‘H 2 S 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, welllogs, 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 H 2 S that could potentially result in atmospheric concentrations of 20 ppm or more in areas not previously classified as having H 2 S present, you must immediately notify BSEE and begin to follow requirements
for areas with H 2 S present.

(e) What are the requirements for conducting simultaneous operations? Whenconducting 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 H 2 S Contingency Plan. Before you begin operations, you must submit an H 2 S 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, andwhat the functions, duties, and responsibilities of those job positions are;

(5) Actions that you will take when
the concentration of H 2 S 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 H 2 S alert. You must have at least two briefing areas on each facility and use the briefing area that is upwind of the H 2 S source at any given time;

(7) Criteria you will use to decidewhen to evacuate the facility and procedures you will use to safely evacuateall personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H 2 S alerts, describe the types of H 2 S emergencies during whichyou consider the risk of helicopter activity to be acceptable and the precautions you will take during the flights;

(8) Procedures you will use to safelyposition all vessels attendant to the facility. Indicate where you will locatethe 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 H 2 S (that constitutes an emergency), howyou will notify them, and their telephone numbers. Include all facilities


### 112 30 CFR Ch. II (7–1–13 Edition) § 250.490

that might be exposed to atmospheric concentrations of 20 ppm or more of
H 2 S;

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

(12) H 2 S detector locations in production facilities producing gas containing 20 ppm or more of H 2 S. Include an ‘‘H 2 S Detector Location Drawing’’ showing:

(i) All vessels, flare outlets,wellheads, and other equipment handling production containing H 2 S;

(ii) Approximate maximum concentration of H 2 S in the gas stream;
and

(iii) Location of all H 2 S sensors included in your contingency plan;

(13) Operational conditions when you expect to flare gas containing H 2 S including the estimated maximum gas flow rate, H 2 S concentration, and duration of flaring;

(14) Your assessment of the risks topersonnel 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 (SO 2 )-detection system(s) you will use
to determine SO 2 concentration and exposure hazard when H 2 S is burned;

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

(19) Personnel protection measures or evacuation procedures you will initiate
when the SO 2 concentration in the atmosphere reaches 5 ppm;

(20) Engineering controls to protect personnel from SO 2 ; and

(21) Any special equipment, procedures, or precautions you will use ifyou 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 H 2 S 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
H 2 S equipment and procedures before beginning duty at your facility;

(ii) Visitors who will remain on yourfacility 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 foremployees, 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 safebriefing areas, alarm system, and hazards of H 2 S and SO 2 ; and

(B) Instructions on their responsibilities in the event of an H 2 S release.

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

(i) Hazards of H 2 S and of SO 2 and theprovisions for personnel safety contained in the H 2 S Contingency Plan;

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

use;

(iii) Location of protective breathing equipment, H 2 S detectors and alarms, ventilation equipment, briefing areas,warning systems, evacuation procedures, and the direction of prevailing winds;


### 113 Safety & Environmental Enforcement, Interior § 250.490

(iv) Restrictions and correctivemeasures 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 H 2 S exposure. During all drills and training sessions, you must address procedures for rescue and
first aid for H 2 S 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 H 2 S 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. Thedrills 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 H 2 S considerations at the facility, and other updated H 2 S information at least monthly.

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

(i) Drilling, well-completion, andwell-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 atall times on facilities with wells capable of producing H 2 S and on facilities that process gas containing H 2 S 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 H 2 S 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-H 2 S,’’ 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 aredisplayed 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, aminimum 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 H 2 S.

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

(i) Illuminate all signs and flags atnight 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 designatedresponsible persons must inform personnel of the level of danger and issueinstructions on the initiation of appropriate protective measures.


### 114 30 CFR Ch. II (7–1–13 Edition) § 250.490

(j) H 2 S-detection and H 2 S monitoring equipment: (1) What are the requirements for an H 2 S detection system? An H 2 S detection system must:

(i) Be capable of sensing a minimum of 10 ppm of H 2 S in the atmosphere;
and

(ii) Activate audible and visual
alarms when the concentration of H 2 S 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 H 2 S 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 H 2 S.

(4) How often must I observe the sensors? During drilling, well-completion and well-workover operations, you must continuously observe the H 2 S levels indicated by the monitors in thework 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 H 2 S 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 H 2 S 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 10feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H 2 S 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
H 2 S around multiple pieces of equipment, provided the sensor is located nomore than 10 feet from each piece, except that you need to use at least twosensors 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 H 2 S
Detectors? (i) Personnel trained to calibrate the particular H 2 S detectorequipment being used must test detectors by exposing them to a known concentration in the range of 10 to 30 ppm
of H 2 S.

(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the appliedconcentration, recalibrate the instrument.

(7) How often must I test my detectors? (i) When conducting drilling, drill stemtesting, well-completion, or wellworkover operations in areas classified
as H 2 S present or H 2 S 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 H 2 S 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 H 2 S-detection and H 2 SVerDate Mar<15>2010 13:26 Aug 06, 2013 Jkt 229122 PO 00000 Frm 00124 Fmt 8010 Sfmt 8010 Y:\SGML\229122.XXX 229122ehiers on DSK2VPTVN1PROD with CFR

### 115 Safety & Environmental Enforcement, Interior § 250.490

monitoring equipment be functionally tested and calibrated more frequently.

(8) What documentation must I keep ? (i) You must maintain records of testingand calibrations (in the drilling or production operations report, as applicable) at the facility to show the presentstatus 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
H 2 S present or H 2 S unknown, you must equip vessels with an H 2 S-detectionsystem that activates audible and visual alarms when the concentration of
H 2 S in the atmosphere reaches 20 ppm. This requirement does not apply to vessels positioned upwind and at a safedistance from the facility in accordance with the positioning procedure described in the approved H 2 S Contingency Plan.

(10) What are the requirements for nearby facilities? The District Manager may require you to equip nearby facilities with portable or fixed H 2 S detector(s)
and to test and calibrate those detectors. To invoke this requirement, theDistrict Manager will consider dispersion modeling results from a possible release to determine if 20 ppm H 2 S concentration levels could be exceeded at nearby facilities.

(11) What must I do to protect against
SO 2 if I burn gas containing H 2 S? You
must:

(i) Monitor the SO 2 concentration in the air with portable or strategicallyplaced fixed devices capable of detecting a minimum of 2 ppm of SO 2 ;

(ii) Take readings at least hourly and at any time personnel detect SO 2 odor or nasal irritation;

(iii) Implement the personnel protective measures specified in the H 2 S Contingency Plan if the SO 2 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 SO 2
. (12) May I use alternative measures? You may follow alternative measures instead of those in paragraph (j)(11) ofthis 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 H 2 S present or H 2 S 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 tofacilities carry appropriate protectivebreathing equipment for each crewmember. The District Manager may require additional protective-breathing equipment on certain vessels attendant to the facility.

(viii) During H 2 S alerts, limit helicopter flights to and from facilities to the conditions specified in the H 2 S Contingency Plan. During authorized flights, the flight crew and passengersmust use pressure-demand-type respirators. You must train all membersof 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-airmanifolds, hoses, and masks at the facility and the briefing areas. You must provide a cascade air-bottle system forthe breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle


### 116 30 CFR Ch. II (7–1–13 Edition) § 250.490

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 H 2 S detectors capable of detecting a 10 ppm concentration of
H 2 S 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 onthe 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 equalto 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 H 2 S or SO 2 may accumulate; and

(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H 2 S or
SO 2 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 sizeand 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 H 2 S 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 H 2 S 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 writtenfollow-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 H 2 S present or H 2 S 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
H 2 S, you must immediately conduct either the Garrett-Gas-Train test or a comparable test for soluble sulfides to confirm the presence of H 2 S.

(3) If the concentration detected by air sensors in over 20 ppm, personnelconducting 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 H 2 S, well-control fluid pH, and corrosion equipment.

(i) Scavengers. You must have scavengers for control of H 2 S available on the facility. When H 2 S is detected, you must add scavengers as needed. Youmust 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 fluidsystem as needed for the control of corrosion.

(5) You must degas well-control fluids containing H 2 S at the optimum location for the particular facility. You must collect the gases removed andburn 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 givingconsideration to personnel safety, possible environmental damage, and possible facility well-equipment damage:


### 117 Safety & Environmental Enforcement, Interior § 250.490

(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 H 2 Sand other gases must be through pressurized or atmospheric mud-separatorequipment depending on volume, pressure and concentration of H 2 S. 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 H 2 S and restore and maintain the proper quality.

(o) Well testing in a zone known to contain H 2 S. When testing a well in a zone
with H 2 S 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 H 2 S 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 H 2 S levels.

(3) Not burn produced gases exceptthrough a flare which meets the requirements of paragraph (q)(6) of this section. Before flaring gas containing
H 2 S, you must activate SO 2 monitoringequipment in accordance with paragraph (j)(11) of this section. If you detect SO 2 in excess of 2 ppm, you must implement the personnel protective measures in your H 2 S 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 H 2 S service. (5) Use tubulars suitable for H 2 S 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 H 2 S 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 H 2 S
service.

(p) Metallurgical properties of equipment. When operating in a zone with
H 2 S 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 H 2 S 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 H 2 S service.

(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H 2 Sbearing fluids in conformance with NACE Standard MR0175–03 (as specified in §250.198).

(3) Use temporary downhole well-security devices such as retrievablepackers and bridge plugs that are designed for H 2 S service.

(4) When producing in zones bearing
H 2 S, 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 H 2 S zone: (1) Coring operations. When you conduct coring operations in H 2 S-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 H 2 S.


### 118 30 CFR Ch. II (7–1–13 Edition) § 250.500

(2) Logging operations. You must treat
and condition well-control fluid in use for logging operations to minimize the
effects of H 2 S on the logging equipment.

(3) Stripping operations. Personnel must monitor displaced well-controlfluid returns and wear protectivebreathing equipment in the workingarea when the atmospheric concentration of H 2 S reaches 20 ppm or if the well is under pressure.

(4) Gas-cut well-control fluid or well kick from H 2 S-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 minimizeexposure 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, abrasivewear on tool joints, and joint imbalance.

(6) Flare system. The flare outlet mustbe 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 wakeeffects 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
H 2 S all vents from production process equipment, tanks, relief valves, burst plates, and similar devices.

(7) Corrosion mitigation. You must useeffective means of monitoring and controlling corrosion caused by acid gases (H 2 S and CO 2 ) in both the downhole andsurface 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 H 2 S exists.

(8) Wireline lubricators. Lubricatorswhich may be exposed to fluids containing H 2 S must be of H 2 S-resistant materials.

(9) Fuel and/or instrument gas. You must not use gas containing H 2 S for instrument gas. You must not use gas containing H 2 S 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 H 2 S-bearing fluids must be constructed of H 2 S-corrosion resistant materials or coated so as to resist H 2 S corrosion.

(11) Elastomer seals. You must use
H 2 S-resistant materials for all sealswhich may be exposed to fluids containing H 2 S.

(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 H 2 S 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 H 2 S. The District Manager may require the submittal of an updated analysis if the water disposal rate or the potential
H 2 S content increases.

(13) Deck drains. You must equip opendeck drains with traps or similar devices to prevent the escape of H 2 S gas into the atmosphere.

(14) Sealed voids. You must take precautions to eliminate sealed spaces inpiping designs (e.g., slip-on flanges, reinforcing pads) which can be invaded by atomic hydrogen when H 2 S is present.



### Subpart E—Oil and Gas WellCompletion Operations

§ 250.500 General requirements.

Well-completion operations shall be conducted in a manner to protectagainst harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas


### 119 Safety & Environmental Enforcement, Interior § 250.510

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 thework 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 samewell-bay which are capable of producing hydrocarbons shall be shut inbelow the surface with a pumpthrough-type tubing plug and at the surface with a closed master valve prior to moving well-completion rigsand related equipment, unless otherwise approved by the District Manager. A closed surface-controlled subsurface safety valve of the pump-through typemay 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 witha 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 wellsor other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller’s console orwell-servicing unit operator’s work station.

§ 250.504 Hydrogen sulfide.

When a well-completion operation is
conducted in zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of H 2 S is unknown (as defined in §250.490 of this part), thelessee shall take appropriate precautions to protect life and property onthe platform or completion unit, including, but not limited to operationssuch 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-completionoperations, crew members shall be instructed in the safety requirements ofthe operations to be performed, possible hazards to be encountered, andgeneral safety considerations to protect personnel, equipment, and the environment. Date and time of safetymeetings 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, andrelated equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading thatmay be encountered during the proposed operations. Prior to moving a well-completion rig or equipment onto a platform, the lessee shall determinethe 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


### 120 30 CFR Ch. II (7–1–13 Edition) § 250.511

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 blockfrom 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 enablesthe District Manager to determine specific operating requirements, fieldwell-completion rules may be established on the District Manager’s initiative or in response to a request from alessee. Such rules may modify the specific requirements of this subpart. After field well-completion rules havebeen 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 toDrill and Supplemental APD Information Sheet (Forms BSEE–0123 andBSEE–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 thecompletion 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, astatement 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 H 2 S or a zone where the presence of H 2 S 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-fluidequipment shall be installed, maintained, and utilized:

(1) A fill-up line above the uppermost BOP;


### 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 ofdrill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drillcollars 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 toan 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 willsafely 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-partyverification 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 surfacepressure. The documentation must include actual shearing and subsequent pressure integrity test results for themost rigid pipe to be used, and calculations of shearing capacity of all pipe to be used in the well including correctionfor 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 registeredprofessional 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 toperform the verification in the appropriate jurisdiction, and evidence todemonstrate 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


### 122 30 CFR Ch. II (7–1–13 Edition) § 250.516

location to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearingram 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 componentsshall exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceedsthe 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 annularpreventer 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 meetthe 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 200psi 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 ratingat 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 alltimes 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.


### 123 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 before12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Managermay 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 testfor 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 toa 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 thetest. 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 subseaBOP 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 stationor 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-piperams 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 ROVfunction, with your APM for BSEE District Manager approval. You must:

(i) Ensure that the ROV hot stabs arefunction 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


### 124 30 CFR Ch. II (7–1–13 Edition) § 250.517

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 theseafloor 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 yourAPM for BSEE District Manager approval. The procedures for these function tests must include documentationof 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 maypostpone a BOP test if you have wellcontrol problems. You must conductthe 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 RP53, Recommended Practices for Blowout Prevention Equipment Systems forDrilling Wells (incorporated by reference as specified in §250.198). Youmust document how you met or exceeded the provisions of Sections 17.10 and18.10 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 seaconditions permit. You may use television cameras to inspect subsea equipment. The BSEE District Manager mayapprove 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 17.12and 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 toBSEE 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 recordthe 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 systemand 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


### 125 Safety & Environmental Enforcement, Interior § 250.520

(7) After completion of the well, you
must retain all the records listed inparagraph (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 thecasing, 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 ratinggreater 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] C ASING P RESSURE M ANAGEMENT

§ 250.519 What are the requirements for casing pressure management?

Once you install your wellhead, youmust 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 betweenAPI RP 90 and the casing pressure requirements of this subpart, you mustfollow 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.


### 126 30 CFR Ch. II (7–1–13 Edition) § 250.521

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 performinga 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 productionon 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 isconsidered a normal and necessary operation to manage thermal casing pressure; therefore, you do not need to evaluate these operations as a casingdiagnostic 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]


### 127 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 diagnostictest 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 demonstratedtubing/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 casingpressure 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 RegionalSupervisor, 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);


### 128 30 CFR Ch. II (7–1–13 Edition) § 250.529

(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 H 2 S that may be present;

(v) Whether the structure on whichthe 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 RegionalSupervisor 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 companymust submit plans for corrective action to the respective District Manager within 30 days of receiving the denial. The District Manager will establish aspecific 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 thesame well requires a casing pressure request; or

(e) A well has more than one casingoperating 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 protectagainst 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 thehighest 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:


### 129 Safety & Environmental Enforcement, Interior § 250.606

(a) Cutting paraffin;(b) Removing and setting pumpthrough-type tubing plugs, gas-lift valves, and subsurface safety valveswhich 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 initialcompletion 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 samewell-bay which are capable of producing hydrocarbons shall be shut inbelow the surface with a pumpthrough-type tubing plug and at the
surface with a closed master valve prior to moving well-workover rigs andrelated equipment unless otherwise approved by the District Manager. A
closed surface-controlled subsurface safety valve of the pump-through-typemay be used in lieu of the pumpthrough-type tubing plug provided that
the surface control has been locked outof 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 pressurevalve 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 orother hydrocarbon flow on the platform.

§ 250.604 Hydrogen sulfide.

When a well-workover operation is
conducted in zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of H 2 S is unknown (as defined in §250.490 of this part), thelessee 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 thewell and permit continued safe production operations.

§ 250.606 Crew instructions.

Prior to engaging in well-workoveroperations, crew members shall be instructed in the safety requirements ofthe operations to be performed, possible hazards to be encountered, andgeneral safety considerations to protect personnel, equipment, and the environment. Date and time of safetymeetings shall be recorded and available at the facility for review by a BSEE representative.


### 130 30 CFR Ch. II (7–1–13 Edition) §§ 250.607–250.608

§§ 250.607–250.608 [Reserved]

§ 250.609 Well-workover structures on fixed platforms.

Derricks, masts, substructures, andrelated equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading thatmay be encountered during the operations proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lesseeshall determine the structural capability of the platform to safely supportthe equipment and proposed operations, taking into consideration thecorrosion 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 shallbe equipped with either remote operated manual or automatic shutdown devices. Diesel engines which are not continuously attended shall beequipped 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 asafety device which is designed to prevent the traveling block from striking
the crown block. The device shall be checked for proper operation weeklyand after each drill-line slipping operation. The results of the operationalcheck shall be entered in the operations log.

§ 250.612 Field well-workover rules.

When geological and engineering information available in a field enablesthe 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 initiativeof 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 lesseereceives 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, astatement 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 H 2 S 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 ofpresent 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 thecase of a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form BSEE–


### 131 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 withdrill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in such fluidlevel 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 postednear the operator’s station. A mechanical, volumetric, or electronic devicefor measuring the amount of well-control fluid required to fill the hold shall
be utilized.

(c) The following well-control-fluidequipment 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 willsafely 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-partyverification 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 surfacepressure. The documentation must include actual shearing and subsequent pressure integrity test results for themost rigid pipe to be used and calculations of shearing capacity of all pipe tobe 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:


### 132 30 CFR Ch. II (7–1–13 Edition) § 250.616

(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 inthis section must be a technical classification society, or a licensed professional engineering firm, or a registeredprofessional 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 toperform the verification in the appropriate jurisdiction, and evidence todemonstrate 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 thelocation to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearingram 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 towhich 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 approvalof the well-workover operation, a wellcontrol procedure that indicates how the annular preventer will be utilized, and the pressure limitations that willbe 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 200psi 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


### 133 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 ofthe valves on the kill line shall be remotely controlled, except that a checkvalve on the kill line in lieu of the remotely controlled valve may be installed provided two readily accessible manual valves are in place and thecheck 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 performedthrough the wellhead inside of conventional tubing using small-diameter jointed pipe (usually 3 ⁄ 4 inch to 1 1 ⁄ 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 mustmeet 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 belocated 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 thecoiled tubing string for all coiled tubing well-workover operations. If you plan to conduct operations withoutdownhole 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 equalto or greater than the working pressure rating of the connection to whichthey are attached, and you must install them between the well control


### 134 30 CFR Ch. II (7–1–13 Edition) § 250.617

stack and the choke or kill line. Foroperations 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 sufficientaccumulator capacity to close-openclose each component in the BOP stack. This cycle must be completedwith 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 beflanged, 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 ofa 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 piperams 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 thework string. A wrench to fit the workstring safety valve shall be readily available. Proper connections shall be readily available for inserting valves inthe 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 mustconduct a low-pressure test and a highpressure test for each component. Youmust 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 andkill lines, and valves, manifolds, strippers, and safety valves. Surface BOP systems must be pressure tested with
water.

(1) Low pressure tests. All BOP systemcomponents 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 systemcomponents must be successfully tested to the rated working pressure of theBOP equipment, or as otherwise approved by the District Manager. The annular-type BOP must be successfullytested 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 sizesof 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, alternatingbetween control stations and at staggered intervals to allow each crew tooperate 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 atleast once every 30 days during operation. A longer period between blowout preventer tests is allowed when there isa stuck pipe or pressure-control operation and remedial efforts are beingperformed. 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.


### 135 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 inwell-workover operations shall participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.

(d) Stump tests. You may conduct astump test for the BOP system on location. A plan describing the stump test procedures must be included in yourForm 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 workingpressure 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 tubingtests on a pressure chart, or with a digital recorder, unless otherwise approved by the District Manager. Thetest interval for each BOP system component must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure testfor 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 BOPsystem, 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 indicatethe 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 BOPtest plan that contains the required information and is retained on file at the facility. (2) The control station used duringthe test shall be identified in the operations log. For a subsea system, thepod 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. Allrecords including pressure charts, operations log, and referenced documents pertaining to BOP tests, actuations, and inspections, shall be available forBSEE 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 yearsat 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 subseaBOP 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 ROVfunction, with your APM for BSEE District Manager approval. You must:

(i) Ensure that the ROV hot stabs arefunction 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


### 136 30 CFR Ch. II (7–1–13 Edition) § 250.618

(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 theseafloor 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 yourAPM for BSEE District Manager approval. The procedures for these function tests must include documentationof 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 RP53, Recommended Practices for Blowout Prevention Equipment Systems forDrilling Wells (incorporated by reference as specified in §250.198). Youmust document how you met or exceeded the provisions of Sections 17.10 and18.10 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 mayapprove 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 17.12and 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 toBSEE 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 pressuretested, 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).


### 137 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 ratinggreater 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, andnonroutine wireline workover operations:

(a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that doesoccur shall be contained to prevent pollution.

(b) All wireline perforating operations and all other wireline operations
where communication exists between the completed hydrocarbon-bearingzone(s) and the wellbore shall use a lubricator assembly containing at least
one wireline valve.

(c) When the lubricator is initiallyinstalled 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 thehuman, 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 apreproduction inspection has been requested by the lessee.

(b) For all new floating productionsystems (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 productionriser standards of API RP 2RD (as incorporated by reference in 30 CFR 250.198);

(3) Design all stationkeeping systems for floating facilities to meet thestandards 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


### 138 30 CFR Ch. II (7–1–13 Edition) § 250.801

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 injectionvalve, 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-controlledSSSVs 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-controlledSSSV has been replaced with a subsurface-controlled SSSV in accordance with paragraph (d)(2) of this sectionshall be equipped with a surface-controlled SSSV when the tubing is first
removed and reinstalled.

(d) Subsurface-controlled SSSVs. Wellsmay 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 beso equipped when the tubing is first removed and reinstalled,

(2) The subsurface-controlled SSSV isinstalled 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 productionis 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 inthe 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 operatingsubsurface-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 thewell 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 (perforatedbut 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 approvedby 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 oran injection valve capable of preventing backflow shall be installed in all injection wells. This requirement is not applicable if the District Manager


### 139 Safety & Environmental Enforcement, Interior § 250.802

concurs that the well is incapable offlowing. The lessee shall verify the noflow condition of the well annually.

(h) Temporary removal for routine operations. (1) Each wireline- or pumpdownretrievable subsurface safety devicemay 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 thesubsurface 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, atrained 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 ona 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 thewell 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 awireline- 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 providefor 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 ofthe ESD by manual action on the platform, the system may be activated bya 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 maintainedin a manner which provides for efficiency, safety of operation, and protection of the environment.

(b) Platforms. You must protect all platform production facilities with abasic 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 requirementsof 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 accordancewith 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.


### 140 30 CFR Ch. II (7–1–13 Edition) § 250.803

(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 systemapplication 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 nearestthe 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, meteringdevices, 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 allowableworking pressures as determined in accordance with API RP 14E, Design and
Installation of Offshore ProductionPlatform 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 RP505, 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 schematicof any platform safety shut-down system with a functional legend.

(5) Certification that the design for the mechanical and electrical systemsto 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 thedetection 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, youmust comply with the following production safety system requirements, in addition to the requirements of §250.802 of this subpart and the requirements ofAPI RP 14C (as incorporated by reference in §250.198).

(b) Design, installation, and operation of additional production systems —(1)
Pressure and fired vessels. Pressureand fired vessels must be designed, fabricated, and code stamped in accordance with the applicable provisions ofSections I, IV, and VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel
Code. Pressure and fired vessels must


### 141 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 thevalve-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 ventsshall 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 operatingat 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 atany 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-insensor 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 availableto the District Manager. The high-pressure shut-in sensor shall be set nohigher 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. Thelow-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 lessthan 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 asignificant 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 than15 percent or 5 psi, whichever is greater, above the highest operating pressure of the line. But in all cases, itshall be set sufficiently below the maximum shut-in wellhead pressure or thegas-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 operatingpressure of the line in which it is installed.

(ii) If a well flows directly to the pipeline before separation, the flowlineand 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 ofliquid 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


### 142 30 CFR Ch. II (7–1–13 Edition) § 250.803

the valve(s) to close before exceedingthe 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 verificationagent’s (IVA’s) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements ofAPI Spec 17J (as incorporated by reference in §250.198);

(B) Determine that the unbonded flexible pipe is suitable for its intendedpurpose 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 beequipped to permit testing with an external pressure source.

(4) ESD. The ESD must conform tothe requirements of Appendix C, section C1, of API RP 14C (as incorporatedby reference in §250.198), and the following:

(i) The manually operated ESD valve(s) shall be quick-opening andnonrestricted 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 onthe 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 officenearest the OCS facility or other location conveniently available to the District Manager.

(5) Engines: (i) Engine exhaust. You must equip engine exhausts to complywith 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 remoteoperated manual or automatic shutdown devices. Diesel engines that are not continuously attended must beequipped with automatic shutdown devices.

(6) Glycol dehydration units. A pressure relief system or an adequate ventshall 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 equipcompressor 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 andinterstage scrubbers shall be designated to actuate automatic shutdownvalves (SDV) located in each compressor suction and fuel gas line so


### 143 Safety & Environmental Enforcement, Interior § 250.803

that the compressor unit and the associated vessels can be isolated from allinput 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 onthe discharge line of all compressor installations of 1,000 horsepower (746 kilowatts) or greater.

(8) Firefighting systems. Firefightingsystems for both open and totally enclosed platforms installed for extreme
weather conditions or other reasonsshall 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 DistrictManager. 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 inenclosed 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 systemhas 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 chemicalsystem 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 evidenceto 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 ventilationwhich 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 andof 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 theguidelines 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 levelsshall 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 classifiedarea do not require a gas detection system.

(iv) The District Manager may require the installation and maintenanceof a gas detector or alarm in any potentially hazardous area.


### 144 30 CFR Ch. II (7–1–13 Edition) § 250.804

(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. Electricalequipment 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 orfields 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 thewells 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 shallbe 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 withthe 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, andhot-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 theinterval specified below or more frequently if operating conditions warrant. Testing must be in accordancewith 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 inplace 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 incorporatedby reference in §250.198) to ensure proper operation.

(ii) Each subsurface-controlled SSSVinstalled 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 byopening the well to possible flow at intervals not exceeding 6 months. If a liquid leakage rate in excess of 200 cubiccentimeters 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.


### 145 Safety & Environmental Enforcement, Interior § 250.804

(iv) Injection valves shall be tested inthe 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 disassembledand 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 testedshall 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 onewellhead SSV and verify a surface-controlled SSSV closure for that well asindicated 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 eachsubsurface 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 shallbe 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


### 146 30 CFR Ch. II (7–1–13 Edition) § 250.805

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 asprovided in paragraph (b)(1) of this section, you may install only certifiedsafety 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. BSEErecognizes two quality assurance programs:

(i) ANSI/ASME SPPE–1–1994 andSPPE–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 plannedto 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 isalready 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 evaluateother quality assurance programs, submit relevant information about the program and reasons for recognition by BSEE to the Chief, Office of OffshoreRegulatory Programs; Bureau of Safety and Environmental Enforcement; MS–4020; 381 Elden Street, Herndon, Virginia 20170–4817.

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

(a) If you plan to install SSSVs andrelated 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 DeepwaterOperations 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 validationand 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.


### 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 atemperature 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 equalto 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 thatwill be exposed to the HPHT environment.

§ 250.808 Hydrogen sulfide.

Production operations in zones known to contain hydrogen sulfide (H 2 S) or in zones where the presence of
H 2 S is unknown, as defined in §250.490of 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

G ENERAL R EQUIREMENTS FOR P LATFORMS

§ 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 andobtain 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 anymodification 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.


### 148 30 CFR Ch. II (7–1–13 Edition) § 250.901

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 theadequacy 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, youmay make repairs to primary structural elements to restore an existingpermitted condition without submitting an application or receiving prior BSEE approval for up to 120-calendardays following an event. You must notify the Regional Supervisor of the damage that occurred within 24 hours of its discovery, and you must providea 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-calendardays 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 becancelled (if installation has not occurred) during the application and approval process. If BSEE cancels yourinstallation 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, BuildingCode 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 Structuresfor 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);


### 149 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, andConstructing Floating Production Systems, (as incorporated by reference in §250.198);

(9) API RP 2I, In-Service Inspection of Mooring Hardware for FloatingDrilling 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 StationKeeping Systems for Floating Structures, (as incorporated by reference in §250.198);

(12) API RP 2SM, RecommendedPractice 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, StandardSpecification 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, StandardSpecification 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 WeldingCode—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, SulfideStress 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 listedunder paragraph (a) of this section insofar as they do not conflict with other provisions of 30 CFR part 250. You mayuse applicable provisions of these documents, as approved by the Regional Supervisor, for the design, fabrication, and installation of platforms such asspars, since standards specifically written for such structures do not exist. You may also use alternative codes, rules, or standards, as approved by theRegional 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 summarizesthe 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;


### 150 30 CFR Ch. II (7–1–13 Edition) § 250.902

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 ofSubpart Q—Decommissioning Activities of this part.

§ 250.903 What records must I keep?

(a) You must compile, retain, andmake 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 theoriginal material test results of all primary structural materials during allstages 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 assteel 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).

P LATFORM A PPROVAL P ROGRAM

§ 250.904 What is the Platform Approval Program?

(a) The Platform Approval Program is the BSEE basic approval process forplatforms 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.


### 151 Safety & Environmental Enforcement, Interior § 250.905

(b) The requirements of the Platform Approval Program must be met by all platforms on the OCS. Additionally, ifyou 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 mustalso 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, leasenumber, 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 fabricationdrawings 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 onwaves, wind, current, tides, temperature, snow and ice effects, marine growth, and water depth. You must submit one copy.


### 152 30 CFR Ch. II (7–1–13 Edition) § 250.906

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-hullinterfaces; foundations, foundation pilings and templates, and anchoringsystems; 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’’
sk etc hes 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 ormarine 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 mustperform a high-resolution or acousticprofiling survey to obtain information on the conditions existing at and near
the surface of the seafloor. You mustcollect information through this survey sufficient to determine the presence of the following features and theirlikely 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


### 153 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 testingprogram for investigating the stratigraphic and engineering properties ofthe 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, deformationproperties, 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 testmethods employed, and the applicability of these methods as they pertain to the quality of the samples, the typeof soil, and the anticipated design application. You must explain how the engineering properties of each soilstratum 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 theRegional Supervisor an overall site investigation report for your platform that integrates the findings of your shallow hazards surveys and geologicsurveys, 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, yourmaximum 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 atthe 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 thestructure. 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


### 154 30 CFR Ch. II (7–1–13 Edition) § 250.909

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.

P LATFORM V ERIFICATION P ROGRAM

§ 250.909 What is the Platform Verification Program?

The Platform Verification Programis the BSEE approval process for ensuring that floating platforms; platforms of a new or unique design; platforms in seismic areas; or platforms located indeepwater 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 ofthe 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-foundedplatforms 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 afloating platform are subject to the Platform Verification Program: (i) Drilling, production, and pipeline risers, and riser tensioning

systems (each platform must be designed to accommodateall 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 VerificationProgram. A major modification includes any modification that increases loading on a platform by 10 percent ormore. A major repair is a corrective operation involving structural members affecting the structural integrity of a portion or all of the platform. Beforeyou 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 toother types of facilities will be determined by BSEE on a case-by-case basis.


### 155 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 allphases 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 inherentlystand 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 modificationsto 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 submitthe following plans to the Regional Supervisor for approval: (a) Design verification plan. You may submit your design verification plan toBSEE 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, aregistered professional civil or structural engineer or equivalent, or a navalarchitect 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 designverification 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 beused 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 islandstructures 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.


### 156 30 CFR Ch. II (7–1–13 Edition) § 250.913

(c) Installation verification plan. The Regional Supervisor must approve your installation verification plan beforeyou 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 tobe inspected. You must specify the acceptance and rejection criteria to beused 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 planis 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 unlessyou 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 RegionalSupervisor’s approval. You must specify whether the nomination is for the design, fabrication, or installationphase 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-partyverification or experience in the design, fabrication, installation, or major modification of offshore oil and gas platforms. This should include fixedplatforms, 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 contactwith 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 ofthe 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 forthe intended service life at the proposed location.


### 157 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 RegionalSupervisor, 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 arecommendation that the Regional Supervisor either accept, request modifications, or reject the proposed design
unless such a recommendation hasbeen 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 theplatform or major modification to ensure that it has been built according to the approved design and the fabrication plan. If the CVA finds that fabricationprocedures are changed or design specifications are modified, the CVA mustinform you. If you accept the modifications, then the CVA must so inform the Regional Supervisor.

(b) Primary duties of the CVA duringthe 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


### 158 30 CFR Ch. II (7–1–13 Edition) § 250.918

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 RegionalSupervisor, 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, andwhen 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 withthe 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 duringthe 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


### 159 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, andwhen 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 theinstallation unless such a recommendation has been previously made in an interim report; and

(6) Provide any additional comments that the CVA deems necessary.

I NSPECTION , M AINTENANCE

, AND

A SSESSMENT OF P LATFORMS

§ 250.919 What in-service inspection requirements must I meet?

(a) You must submit a comprehensive in-service inspection report annuallyby 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 inspectionfor 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 initialreport 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 thatmay adversely affect structural integrity, an assessment of the structure’s ability to withstand any anticipatedenvironmental conditions, and any remediation plans. Under §§250.900(b)(3) and 250.905, you must obtain approvalfrom 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 inAPI RP 2A–WSD, Section 17.3 (as incorporated by reference in §250.198). IfBSEE 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 loadingsfor the appropriate assessment category.

(b) You must perform an analysischeck when your platform will have additional personnel, additional topside facilities, increased environmental or operational loading, or inadequatedeck height your platform suffered significant damage (e.g., experienced damage to primary structural members orconductor 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 yourmitigation actions (e.g., repair, modification, decommissioning) to the Regional Supervisor for approval before you conduct the work.


### 160 30 CFR Ch. II (7–1–13 Edition) § 250.921

(d) The BSEE may require you to conduct a platform design basis checkwhen the reduced environmental loading criteria contained in API RP 2A– WSD Section 17.6 are not applicable.

(e) By November 1, 2009, you mustsubmit a complete list of all the platforms you operate, together with allthe 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 Supervisorfor 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 ensurethat 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, andabandoned to provide safe and pollution-free transportation of fluids in amanner 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 ofany 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 existingpipelines 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 transferpoint on a schematic located on the facility.

(iii) If a transfer point is located below water, then the operator mustidentify 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, theBSEE 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 Supervisorto request an exception to this requirement for an individual facility or area.The Regional Supervisor, in consultation with the OPS Regional Directorand affected parties, may grant the request.


### 161 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 requirementsuntil 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 withoutfirst connecting to a transporting operator’s facility on the OCS must complywith 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 thatvalve as the last point BSEE will exercise its regulatory authority.

(9) A pipeline segment is not subjectto BSEE regulations for design, construction, operation, and maintenance
if:

(i) It is downstream (generally shoreward) of the last valve and associatedsafety 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 regulationsgoverning 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 statesthe justification for the pipeline to operate under DOT regulation.

(ii) The Regional Supervisor will decide, on a case-by-case basis, whetherto grant the operator’s request. In considering each petition, the Regional Supervisor will consult with the Officeof Pipeline Safety (OPS) Regional Director.

(13) A transporter who operates a pipeline regulated by DOT may request to operate under BSEE regulationsgoverning 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 Supervisorand 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 andgranted in accordance with this subpart.

(e)(1) The Regional Supervisor may suspend any pipeline operation upon adetermination by the Regional Supervisor that continued activity wouldthreaten or result in serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, mineral deposits, or themarine, coastal, or human environment.

(2) The Regional Supervisor may alsosuspend pipeline operations or a rightof-way grant if the Regional Supervisordetermines that the lessee or right-ofway holder has failed to comply with aprovision 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).


### 162 30 CFR Ch. II (7–1–13 Edition) § 250.1001

§ 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 associatedsafety equipment) on the last production facility on the OCS that do notconnect 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 pipelinescurrently operated under DOT requirements governing design, construction, maintenance, and operation;

(2) Producer-operated pipelines thatDOI 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 safetyequipment) 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 iscovered 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 fromother 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 oroperator 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 forsteel 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.


### 163 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 fromTable 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 referencein §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). Eachflange 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 whichit is anticipated that it might be subjected in service.

(3) Pipeline fittings shall have pressure-temperature ratings based onstresses 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 otherfloating platforms according to the design standards of API RP 2RD, Designof 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 settinglevel 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 8 5 ⁄ 8 inches in diameter and installed in water depths of less than 200 feet shall be buried to a depth of at least 3 feetunless they are located in pipeline congested areas or seismically active areasas determined by the Regional Supervisor. Nevertheless, the Regional Supervisor may require burial of anypipeline if the Regional Supervisor determines that such burial will reducethe 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 determinewhether 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


### 164 30 CFR Ch. II (7–1–13 Edition) § 250.1004

such items present no hazard to trawling or other operations. A protectivedevice 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 atpipeline 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 requiredwhen 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 shallbe 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 temperaturerecorder measuring test fluid temperature synchronized with a pressure recorder along with deadweight testreadings shall be employed for all pressure testing. When a pipeline is pressure tested, no observable leakage shallbe 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 orweakened 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 properinstallation, 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 visualalarms 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-pressuresensors (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 andconnected 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 acontinuous 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 ofthe foregoing, a system capable of detecting leaks in the pipeline may be


### 165 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 blockvalve 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 onlybe equipped with an FSV installed immediately upstream of each casing annulus or the first inlet valve on the christmas tree.

(8) Bidirectional pipelines shall beequipped with a PSHL and an SDV immediately upon boarding each platform.

(9) Pipeline pumps must comply withsection A7 of API RP 14C (as incorporated by reference in §250.198). The setting levels for the PSHL devices arespecified in paragraph (b)(3) of this section.

(c) If the required safety equipment
is rendered ineffective or removed fromservice 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 inspectedat time intervals and methods prescribed by the Regional Supervisor forindication 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 annuallyby taking measurements of pipe-toelectrolyte potential.

§ 250.1006 How must I decommissionand 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 therequirements 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 leaseterm pipeline or for a pipeline right-ofway grant must be submitted in quadruplicate to the Regional Supervisor. Right-of-way grant applications mustinclude 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; connectingfacilities; 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 beconnected 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 terminalpoint. A plat(s) submitted for a pipeline right-of-way shall bear a signedcertificate upon its face by the engineer who made the map that certifiesthat the right-of-way is accurately represented upon the map and that the design characteristics of the associatedpipeline are in accordance with applicable regulations.


### 166 30 CFR Ch. II (7–1–13 Edition) § 250.1008

(2) A schematic drawing showing the size, weight, grade, wall thickness, andtype 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, andblock valves; and manifolds. This schematic drawing shall also show inputsource(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 workingpressure; and associated safety equipment and pig launchers and receivers. The schematic must indicate the pointon 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 unbondedflexible 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 morepipeline risers for a tension leg platform or other floating platform, your application must include:

(A) The design fatigue life of theriser, 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 pipelineor conducting a pressure test on a pipeline.

(b) The lessee or right-of-way holder shall submit a report to the RegionalSupervisor within 90 days after completion of any pipeline construction. The report, submitted in triplicate, shall include an ‘‘as-built’’ location platdrawn to a scale specified by the Regional Supervisor showing the location, length in Federal waters, and X–


### 167 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 platsshall be certified by a registered engineer or land surveyor and show the boundaries of the right-of-way asgranted. If there is a substantial deviation of the pipeline route as grantedin 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 formore 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 therepair of a pipeline or pipeline component to the Regional Supervisor within30 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 thefailure. A comprehensive written report of the information obtained shallbe submitted by the lessee to the Regional Supervisor as soon as available.

(g) If the effects of scouring, soft bottoms, or other environmental factorsare 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-electrolytepotential 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 andother regulations of this part, regulations of the Department of Transportation, Department of the Army, andthe 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 andgranted 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 Districtof Columbia, or of any State; or associations of such citizens, nationals, resident aliens, or private, public, ormunicipal corporations, States, or political subdivisions of States.

(b) A right-of-way shall include thesite on which the pipeline and associated structures are to be situated, shall
not exceed 200 feet in width unless safety and environmental factors duringconstruction 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 shallcomply with applicable laws and regulations and the terms of the grant.


### 168 30 CFR Ch. II (7–1–13 Edition) § 250.1011

(b) The granting of the right-of-wayshall 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 theUnited 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 theright-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 operationswithin the area of the discovery and report the discovery to the Regional Director. If investigations determine thatthe resource is significant, the Regional Director will inform the rightof-way holder how to protect it.

(d) The Regional Supervisor shall bekept informed at all times of the rightof-way holder’s address and, if a corporation, the address of its principalplace 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 Statesagainst 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 oilor 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 otherthings, 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 FERCmay 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 ofSafety 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 alongthe right-of-way. All of these improvements shall be removed by the holder within 1 year of the effective date ofthe relinquishment, forfeiture, or cancellation unless this requirement iswaived 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 thesite. Furthermore, the holder is responsible for accidents or damages which might occur as a result of failure to timely remove improvements andequipment 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 theregulations at 30 CFR part 1218, an annual rental of $15 for each statute mile,


### 169 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 annualrental 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 annualrental 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, thenyou 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-wayapplication. You must make all subsequent payments before the respective time periods begin.

(e) Late payments. An interest chargewill 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 forforfeiture of the grant in an appropriate judicial proceeding instituted by the United States in any U.S. DistrictCourt 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 inthe grant. Temporary cessation or suspension of pipeline operations shall not cause the grant to expire. However, if the purpose of the grant ceases to existor 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 usedbefore the application is made, the application must state the date such usebegan, 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


### 170 30 CFR Ch. II (7–1–13 Edition) § 250.1016

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. Anapplicant 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 acertified copy of the articles of association or appropriate reference to a copy of such articles already filed withBSEE 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 sealshowing 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 isintersected by the proposed right-ofway. The application shall also includea 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 theapplication 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 ofparagraph (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 evaluationand determinations, the Regional Supervisor may request and considerviews 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 Supervisorshall give consideration to any recommendation by the intergovernmental planning program, or similarprocess, 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 Staterecommendation 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 thispart 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 nottake 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 affordedat least 30 days from the date determined in paragraph (c)(1) of this section in which to submit comments.


### 171 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 theright-of-way. In such case, the applicant, upon a request filed within 30 days after receipt of the notification ofsuch 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 mayprescribe, as conditions to the right-ofway grant, stipulations necessary toprotect human, marine, and coastal environments, life (including aquatic life), property, and mineral resourceslocated on or adjacent to the right-ofway.

(2) If the Regional Supervisor determines that a change in the applicationshould be made, the Regional Supervisor shall notify the applicant that anamended 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 adeviation 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, andwithin 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 maybe 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 temporarilyprohibit 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 intriplicate with the Regional Supervisor.

(b) Any application for approval for an assignment, in whole or in part, ofany right, title, or interest in a rightof-way grant must be accompanied by the same showing of qualifications ofthe 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. Theassignee 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 ofparagraph (b) of this section, the requirement to pay a filing fee under


### 172 30 CFR Ch. II (7–1–13 Edition) § 250.1019

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 theholder 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 filedsubject 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

G ENERAL

§ 250.1150 What are the general reservoir production requirements?

You must produce wells and reservoirs at rates that provide for economic development while maximizingultimate recovery and without adversely affecting correlative rights.

W ELL T ESTS AND S URVEYS

§ 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 thecopies 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 formationduring completion, recompletion, reworking, or treatment operations before you start a well test;

(2) Produce the well completion
under stabilized rate conditions for atleast 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 followingtests and complete them within a specified time period:

(1) A retest or a prolonged test of a well completion if it is determined tobe 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, youmust provide advance notice to the Regional Supervisor of the times and
dates of well tests.


### 173 Safety & Environmental Enforcement, Interior § 250.1158

§§ 250.1153–250.1155 [Reserved]

A PPROVALS P RIOR TO P RODUCTION

§ 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 withina 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, avoidthe 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 within500 feet of the completion, if the adjacent acreage is a leased block in theFederal 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 providethe Regional Supervisor letters of acceptance or objection. If an adjacent operator does not respond within 30days, 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 whetheror 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 approvalto 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 includethe 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 reservoirsproposed 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 operatorshave 30 days after notification to provide the Regional Supervisor with letters of acceptance or objection. If thenotified operators do not respond within the specified period, the Regional Supervisor will assume the operators


### 174 30 CFR Ch. II (7–1–13 Edition) § 250.1159

do not object and proceed with a decision.

P RODUCTION R ATES

§ 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 areservoir, 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 limitationsimposed 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.

F LARING , V ENTING

, AND B URNING H YDROCARBONS

§ 250.1160 When may I flare or vent gas?

(a) You must request and receive approval from the Regional Supervisor toflare 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 H 2 S. 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, andreason 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 MCFper 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 48continuous 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.


### 175 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 volumeapproved 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 cannotcontact 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 inthis part, in order to prevent air quality degradation or loss of reserves.

(e) If you flare or vent gas withoutthe required approval, or if the Regional Supervisor determines that you were negligent or could have avoidedflaring 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 requireapproval 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 dataindicating 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 toburn 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 isnot 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 payroyalties 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 gasflaring 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 metersregularly, in accordance with the manufacturer’s recommendation, or at least once every year, whichever is shorter; and


### 176 30 CFR Ch. II (7–1–13 Edition) § 250.1164

(4) You must use and maintain the
flare/vent meters for the life of the facility.

(b) You must report all hydrocarbonsproduced from a well completion, including all gas flared, gas vented, and liquid hydrocarbons burned, to Office
of Natural Resources Revenue on FormONRR–4054 (Oil and Gas Operations Report), in accordance with 30 CFR
1210.102.

(1) You must report the amount ofgas 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. Gasflared 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 methodspecified in paragraph (b)(3) of this section.

(c) You must prepare and maintainrecords 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 2years and have them available for inspection by BSEE representatives.

(2) After 2 years, you must maintainthe records, allow BSEE representatives to inspect the records upon request and provide copies to the Regional Supervisor upon request, but arenot 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 hydrocarbonburning, on a daily and monthly cumulative basis;

(iii) A list of the wells contributing to gas flaring, gas venting, and liquidhydrocarbon 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 maintainthe recordings, allow BSEE representatives to inspect the recordings upon request and provide copies to the Regional Supervisor upon request, but arenot required to keep them on the facility.

(iii) These recordings must includethe 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 requirementsfor flaring or venting gas containing H 2 S?

(a) You may not vent gas containing
H 2 S, except for minor releases during maintenance and repair activities that
do not result in a 15-minute timeweighted average atmosphere concentration of H 2 S of 20 ppm or higher anywhere on the platform.

(b) You may flare gas containing H 2 S only if you meet the requirements of§§250.1160, 250.1161, 250.1163, and the following additional requirements:


### 177 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 H 2 S. The Regional Supervisor will use information provided in
the lessee’s H 2 S 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 orgroup of facilities may significantly affect the air quality of an onshore area, the Regional Supervisor may require you to conduct an air quality modelinganalysis, 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 H 2 S. Each report must contain, on a daily
basis:

(1) The volume and duration of each flaring and venting occurrence;

(2) H 2 S concentration in the flared or vented gas; and

(3) The calculated amount of SO 2 emitted.

O THER R EQUIREMENTS

§ 250.1165 What must I do for enhanced recovery operations?

(a) You must promptly initiate enhanced oil and gas recovery operationsfor all reservoirs where these operations would result in an increase in ultimate recovery of oil or gas undersound 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 planmust include, for each project reservoir, a geologic and engineering overview, Form BOEM–0127, and supporting data as required in §250.1167, 30 CFR550.1167, 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 theactivities 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 jointlydetermine appropriate reporting requirements to minimize or eliminate duplicate reporting requirements.

(c) [Reserved]

§ 250.1167 What information must Isubmit 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 leaseline and the orientation of representative seismic lines or cross-sections .................................. ........................ ✔ ✔ ✔


### 178 30 CFR Ch. II (7–1–13 Edition) § 250.1200

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 thereservoir(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 approvalrequested, 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.


### 179 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 sectionhave 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 beyondyour 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 installationthat 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, includingthose necessary to put gas into marketable conditions such as naturalpressure 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 —amonthly statement showing the volume and quality of the inlet or fieldgas 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.


### 180 30 CFR Ch. II (7–1–13 Edition) § 250.1202

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 liquidhydrocarbon 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 volumeof gas, oil, or other components removed, saved, or sold from a Federal
lease.

Royalty tank —an approved tank inwhich 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 atwhich gas and liquid hydrocarbon volumes and quality are reported. The standard temperature base is 60 ° F.

Verification/Calibration —testing and correcting, if necessary, a measuringdevice 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-approvedmeasurement and/or allocation procedures. Your application (which mayalso 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 andprocedures that will accurately measure the liquid hydrocarbons produced from a lease or unit to comply with the


### 181 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, Section2 (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); whenobtaining net standard volume and associated measurement parameters; and

(4) When requested by the RegionalSupervisor, 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 aschanges 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 thesample before removal from the container; and


### 182 30 CFR Ch. II (7–1–13 Edition) § 250.1202

(iii) The sample probe is in the center half of the pipe diameter in a vertical run and is located at least three pipediameters downstream of any pipe fitting within a region of turbulent flow. The sample probe can be located in ahorizontal 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 thatthe 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 therun 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 beginningof the month and immediately after establishing the monthly meter factor or
a malfunction meter factor.

(4) Send all run tickets for royaltymeters 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 testmeasures 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 usingit to determine operating meter factors;

(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as the liquid hydrocarbons that flowthrough the operating meter to calibrate the master meter;

(3) Calibrate the master metermonthly, 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 flowcheck valves associated with the operating meter. However, the mastermeter may be installed either upstream or downstream of the operating meter; and

(6) Keep a copy of the master metercalibration 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 theAPI 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 calibrationreport to the Regional Supervisor within 15 days after the calibration.

(g) What correction factors must I usewhen proving meters with a mechanicaldisplacement prover, tank prover, or master meter ? Calculate the following correction factors using the API MPMS as


### 183 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, youmust record proof runs until three consecutive runs produce a total meter factor difference of no greater than0.0005. 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 finalmeter 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 throughthe 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 meterproving exceed the run tolerance criteria and all measures excluding theadjustment 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 theAPI 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


### 184 30 CFR Ch. II (7–1–13 Edition) § 250.1203

(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 ifthe 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 andprove 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 beforeusing 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 othermeasurement parameters by using corrections factors and procedures in theAPI MPMS as incorporated by reference in 30 CFR 250.198, including: APIMPMS 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 RegionalSupervisor 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, andtest measurement equipment and procedures to ensure accurate and
verifiable measurement. You must follow the recommendations in API MPMS or RP and AGA as incorporatedby 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 consistentlevels 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 RegionalSupervisor, 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 andat 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 RegionalSupervisor, submit copies of gas volume statements for each requested gas meter. Show whether gas volumes and


### 185 Safety & Environmental Enforcement, Interior § 250.1204

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 metersmonthly, but do not exceed 42 days between verifications/calibrations. Whena 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 bedetermined, 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 istransferred 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 inspectthe 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 approvedcommingling procedures. Your application (which may also include any relevant liquid hydrocarbon and gasmeasurement 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 Statelease production into a Federal commingling system must provide volumetric or fractional analysis data on the State lease production through the designated system operator.


### 186 30 CFR Ch. II (7–1–13 Edition) § 250.1205

(b) What are the requirements for a periodic well test used for allocation ? You
must:

(1) Conduct a well test at least onceevery 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 RegionalSupervisor), 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 ofliquid 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-linevalves, 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 unitizationsituations. 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 andother OCS lessees may ask the Regional Supervisor to approve a requestfor 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 productivereservoir if unitized operations are necessary to:

(1) Prevent waste; (2) Conserve natural resources; or


### 187 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 tominimize 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 enterinto 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 Supervisororders or approves a suspension of production under §250.170.

(e) Unit operating agreement. The unitoperator 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 liabilitiesincurred 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 thispart 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 areaadjusts 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 aunit 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 unitceases drilling activities for a reasonable time period between the delineation of one or more reservoirs and theinitiation 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 §250.170in 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 todevelop 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 competitivereservoir under either a joint Development and Production Plan, submitted to BOEM or a unitization agreement. A competitive reservoir has one or moreproducing or producible well completions on each of two or more leases, or portions of leases, with different lease operating interests. For purposes ofthis paragraph, a producible well completion is a well which is capable of production and which is shut in at the


### 188 30 CFR Ch. II (7–1–13 Edition) § 250.1303

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 iscompetitive. When you receive the preliminary determination, you have 30days (or longer if the Regional Supervisor allows additional time) to concuror 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 ajoint plan of operations. You must submit the joint plan within 90 days after the Regional Supervisor makes a final
determination that the reservoir iscompetitive. 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 lesseemust 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 arenot 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 amodel unit agreement for you to follow. If BSEE revises the model, BSEE will publish the revised model in the
F EDERAL R EGISTER . If you vary yourunit 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 unitagreement, the unit operating agreement, and the initial plan of operationwith 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 previouslyapproved 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 operationswithin a proposed unit area is necessary to prevent waste, conserve natural resources of the OCS, or protect correlative rights, including Federalroyalty interests, the Regional Supervisor may require unitization.

(b) If you ask BSEE to require unitization, you must file a request withthe Regional Supervisor. You must include a proposed unit agreement as described in §§250.1301(d) and 250.1303(b); a proposed unit operating agreement; aproposed initial plan of operation; supporting geological, geophysical, andengineering 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 compulsoryunitization. Lessees who seek compulsory unitization must simultaneouslyserve on the nonconsenting lessees copies of:


### 189 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 planand a statement of reasons for the proposed unitization.

(d) The Regional Supervisor will notrequire 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 itwithin 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 30days after BSEE provides written notice of the hearing date to all parties owning interests that would be madesubject to the unit agreement. The Regional Supervisor must give all lesseesof 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 proceduresare 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 forthe 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 issuean 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

O UTER C ONTINENTAL S HELF L ANDS A CT C IVIL P ENALTIES

§ 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 thebasis of available evidence, that a violation occurred and a civil penalty review is appropriate, it will prepare acase 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 recordof evidence related to the alleged violation.

Civil penalty means a fine. It is a BSEE regulatory enforcement tool
used in addition to Notices of Incidentsof Noncompliance and directed suspensions of production or other operations.

Reviewing Officer means a BSEE employee assigned to review case files and assess civil penalties.


### 190 30 CFR Ch. II (7–1–13 Edition) § 250.1403

Violation means failure to comply
with the Outer Continental ShelfLands 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, athreat 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 otheraquatic 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 Officermay 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 acopy 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 orafter the meeting and submittal of additional information, the ReviewingOfficer 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 theamount of the penalty to the appropriate Leasing Office in the Regionwhere 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 penaltywas 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


### 191 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 Directordetermines the appeal should be covered by a lease-specific abandonmentaccount 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 willtake one or more of the following actions:

(1) We will collect the amount youwere 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 Departmentof the Interior’s regulations implementing these authorities are found at 43 CFR part 12, subpart D.

F EDERAL O IL AND G AS R OYALTY M AN

AGEMENT A CT C IVIL P ENALTIES D EFI

NITIONS

§ 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.

P ENALTIES A FTER A P ERIOD T O C ORRECT

§ 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 sendyou 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 theBOEM 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 afteryou 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 foras 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 afteryou receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified inthat 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 aslong 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 thedate you received the Notice of Noncompliance with the Hearings Division (Departmental), Office of Hearings and


### 192 30 CFR Ch. II (7–1–13 Edition) § 250.1455

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 theaccrual 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 financialsolvency, 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 interestthereon, 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 ahearing on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the amount ofa 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, youmay not contest your underlying liability for civil penalties.

(b) You must file your request within 10 days after you receive the Notice ofCivil Penalty with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of theInterior, 801 North Quincy Street, Arlington, Virginia 22203.

P ENALTIES W ITHOUT A P ERIOD T O C ORRECT

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

The Federal Oil and Gas RoyaltyManagement 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 5business 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 oilor 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 knowthat such oil or gas was stolen or unlawfully removed or diverted.

§ 250.1461 How will BSEE inform me ofviolations 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, howto correct it, and the penalty assessment. We will serve the Notice of Noncompliance and Civil Penalty by registered mail or personal service using


### 193 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 ofNoncompliance 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 ofNoncompliance with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of theInterior, 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 penaltieswill 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 hearingon 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 financialsolvency, 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 interestthereon, 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 ahearing on the Notice of Noncompliance?

(a) You may request a hearing on the record to challenge only the amount ofa civil penalty when you receive a Notice of Civil Penalty regarding violations without a period to correct, ifyou 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 andAppeals, U.S. Department of the Interior, 801 North Quincy, Arlington, Virginia 22203.

G ENERAL P ROVISIONS

§ 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 beconducted by a Departmental Administrative Law Judge from the Office ofHearings 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,


### 194 30 CFR Ch. II (7–1–13 Edition) § 250.1474

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 CivilPenalty, 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 pendingits 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 reviewof 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 issubject 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.

C RIMINAL P ENALTIES

§ 250.1480 May the United Statescriminally 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 penaltiesas provided at 30 U.S.C. 1720, in addition to any authority for prosecution
under other statutes.

B ONDING R EQUIREMENTS

§ 250.1490 What standards must my BOEM-specified surety instrument meet?

(a) A BOEM-specified surety instrument must be in a form specified in


### 195 Safety & Environmental Enforcement, Interior § 250.1496

BOEM instructions. BSEE will give you written information and standardforms 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 mustbe 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 periodof 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. Theamount 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 interestwe 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 suretyinstrument that covers multiple appeals. You may change the instrumentto 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.

F INANCIAL S OLVENCY R EQUIREMENTS

§ 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, 3801Centerpoint 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 financialsolvency as long as you have active appeals, or whenever BSEE requests.

(c) If you demonstrate financial solvency in the current calendar year, youare not required to redemonstrate financial solvency for new appeals of orders during that calendar year unlessyou file for protection under any provision of the U.S. Bankruptcy Code (Title 11 of the United States Code), or BSEEnotifies 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


### 196 30 CFR Ch. II (7–1–13 Edition) § 250.1497

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 suretyunder §§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 suretyunder §§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 CFR250.126. 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 thedate we first determined that you demonstrated financial solvency, as long asyou are not able to demonstrate financial solvency under paragraph (a) ofthis section and you have active appeals.

(d) If you request that we consult abusiness-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 programinformation demonstrates your financial solvency to our satisfaction, our bond-approving officer will not requireyou 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 requireyou 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), BOEMwill determine your net worth as described under §250.1496(b) and (c) to evaluate your financial solvency atleast 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 programannually 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 orother 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 ofthe 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).


### 197 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 termlessee 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 mustspecify the intervals for periodic training and periodic assessment of training needs in their training programs.

Production operations include, but arenot limited to, separation, dehydration, compression, sweetening, and metering operations.

Production safety includes measures, practices, procedures, and equipmentto ensure safe, accident-free, and pollution-free production operations, as wellas 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. Itincludes measures, practices, procedures and equipment, such as fluid flowmonitoring, to ensure safe and environmentally protective drilling, completion, abandonment, and workover operations as well as the installation, repair, maintenance, and operation ofsurface 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 ensurethat 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 ofyour employees are trained to competently perform their assigned well control, deepwater well control, and production safety duties. You must verify that your employees understandand 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. Yourtraining plan must specify the method(s) of verifying employee understanding and performance. This planmust 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 wellcontrol, 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.


### 198 30 CFR Ch. II (7–1–13 Edition) § 250.1504

§ 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 shouldbe 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, wellcontrol, deepwater well control, or production safety practices;

(b) Establish procedures to verify adequate retention of the knowledgeand 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 periodictraining 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, deepwaterwell control, and production safety duties. You are responsible for the costs associated with this testing, excludingsalary 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 atan 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 presentposition, 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 yourcontractor 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 presentposition, years of total oil field experience, and employer’s name (e.g., operator, contractor, or sub-contractor company name); and


### 199 Safety & Environmental Enforcement, Interior § 250.1603

(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, wemay 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 inaccordance 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 fishand 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 isused 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 thenumber of long tons of sulphur produced during a certain period of time, usually per day.

§ 250.1602 Applicability.

(a) The requirements of this subpartP are applicable to all exploration, development, and production operations under an OCS sulphur lease. Sulphuroperations include all activities conducted under a lease for the purpose of discovery or delineation of a sulphur deposit and for the development andproduction of elemental sulphur. Sulphur operations also include activitiesconducted for related purposes. Activities conducted for related purposes include, but are not limited to, production of other minerals, such as salt, foruse in the exploration for or the development and production of sulphur. The lessee must have obtained the right toproduce and/or use these other minerals.

(b) Lessees conducting sulphur operations in the OCS shall comply withthe 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 Managerwill determine whether a sulphur deposit has been defined that contains sulphur in paying quantities ( i.e., sulphur in quantities sufficient to yield areturn in excess of the costs, after completion of the wells, of producing minerals at the wellheads).


### 200 30 CFR Ch. II (7–1–13 Edition) § 250.1604

(b) A determination under paragraph (a) of this section shall be based upon the following:

(1) Core analyses that indicate thepresence 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 relatedequipment on and off an offshore platform, or from one well to another wellon the same offshore platform, including rigging up and rigging down, shall
be conducted in a safe manner.

(b) Hydrogen sulfide (H 2 S). When adrilling, well-completion, wellworkover, or production operation is being conducted on a well in zones
known to contain H 2 S or in zones where the presence of H 2 S is unknown (as defined in §250.490 of this part), thelessee shall take appropriate precautions to protect life and property, especially during operations such as dismantling wellhead equipment and flow lines and circulating the well. Thelessee shall also take appropriate precautions when H 2 S is generated as a result of sulphur production operations.The lessee shall comply with the requirements in §250.490 of this part aswell as the requirements of this subpart.

(c) Welding and burning practices and procedures. All welding, burning, andhot-tapping activities involved in drilling, well-completion, well-workover orproduction operations shall be conducted with properly maintained equipment, trained personnel, and appropriate procedures in order to minimizethe 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 involvedin drilling, well-completion, wellworkover, and production operations shall be designed, installed, equipped, protected, operated, and maintained so as to minimize the danger to life andproperty 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 thepotential loads and conditions of loading that may be encountered duringthe 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 blockfrom 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 availablefor 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


### 201 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), inaccordance 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 andreported 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 thelessee fails to provide sufficient information pursuant to 30 CFR 550.211 through 550.228 and 30 CFR 550.241through 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 Managerbefore approval is granted for commencing drilling operations.

(e) Tests, surveys, and samples. (1) Lessees shall drill and take cores and/orrun 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 intervalsnot 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 notexceeding 500 feet prior to or upon setting a string of casing, or productionliner, 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 willbe acceptable as fulfilling the applicable requirements of this paragraph.

(4) Wells are classified as vertical if the calculated average of inclinationreadings 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 readingsweighted by the length of the respective interval between readings from thesurface to drilled depth exceeds 3 degrees, the well is classified as directional.

(5) At the request of a holder of anadjoining 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 drillingplatforms 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


### 202 30 CFR Ch. II (7–1–13 Edition) § 250.1606

be equipped with either remote-operated manual or automatic-shutdown devices. Diesel engines that are not continuously attended must beequipped 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 thebest 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 andmaintain 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 DistrictManager to determine specific operating requirements, field rules may beestablished 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 DistrictManager or upon the request of a lessee.

§ 250.1608 Well casing and cementing.

(a) General requirements. (1) For the purpose of this subpart, the severalcasing strings in order of normal installation are:

(i) Drive or structural, (ii) Conductor, (iii) Cap rock casing, (iv) Bobtail cap rock casing (requiredwhen 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 ameans 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 anticipatedstresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. Safety factors in the drilling and casing program designsshall 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 shallevaluate the adequacy of the cementing operations by pressure testing thecasing shoe. If the test indicates inadequate cementing, the lessee shall initiate remedial action as approved bythe District Manager. For cap rock casing, the test for adequacy of cementingshall be the pressure testing of the annulus between the cap rock and the conductor casings. The pressure shall


### 203 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 toprovide 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 andsetting depths shall be based upon relevant engineering and geologic factors including the presence or absence of hydrocarbons, potential hazards, andwater depths. The proposed casing setting depths may be varied, subject to District Manager approval, to permitthe casing to be set in a competent formation or through formations determined desirable to be isolated from thewellbore by casing for safer drilling operations. However, the conductor casing shall be set immediately prior todrilling 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 containoil 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 observationof 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. Whengeologic 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 shallbe 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 theprevious 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. Allcasing 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 subjectto 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.


### 204 30 CFR Ch. II (7–1–13 Edition) § 250.1610

(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 allother casing strings. Cement is considered under pressure if one or more floatvalves 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 thenumber 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 200psi 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 devicesalternately 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 oneon 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 thekill 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, methodof 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 ratedworking 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


### 205 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/orvariable-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 tothe 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 bepressure 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 safetyvalves shall be pressure tested to piperam test pressures. Safety valves withproper 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 pressuretests, 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 morethan 7 days between BOP tests is allowed when there is a stuck drill pipeor 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 pressuretest 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. Themanufacturer’s recommended inspection and maintenance procedures are


### 206 30 CFR Ch. II (7–1–13 Edition) § 250.1612

acceptable as guidelines in complying with this requirement.

(f) The lessee shall record pressureconditions during BOP tests on pressure charts, unless otherwise approvedby 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 certifiedas 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 indicatethe 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 BOPtest 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 yearsat 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 beequipped 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 divertersystem 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) downstreamof 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 ofrigid pipe if the flexible hose has integral end couplings. The entire diverter system shall be firmly anchored andsupported to prevent whipping and vibrations. All diverter control equipment and lines shall be protected fromphysical 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 outletsare 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 subsequentpressure tests. The diverter sealing element, diverter valves, and diverter control systems (including the remote)


### 207 Safety & Environmental Enforcement, Interior § 250.1617

shall be actuation tested, and the diverter lines shall be tested for flow prior to spudding and thereafter atleast 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 therelated 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 precautionsin enclosed mud handling areas as prescribed in §§250.455 through 250.459 of this part, except that the installationof 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 ofthe 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 shallmaintain 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 ofsubpart 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 aBOEM-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 paymentof 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 tobe 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 aredefined as the pressure that can reasonably be expected to be exerted upon a casing string and its related wellheadequipment). In the calculation of anticipated surface pressure, the lessee shall take into account the drilling,


### 208 30 CFR Ch. II (7–1–13 Edition) § 250.1618

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 thestatement 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 H 2 S 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 majordrilling equipment, proposals to deepen, sidetrack, complete, workover, or plug back a well, or engage in similar activities to the District Manager onForm 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 depthand production zone, and the well’s capability to produce. Within 30 daysafter 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.


### 209 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 OCSfacility 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 thewellbore; and all other information required by the District Manager in theinterests 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 aftertermination of the suspension or temporary prohibition or within 30 days after the completion of any activitiesrelated 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, orForm 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 afrequency 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 reportsand 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 otheraquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and notleased), 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 beencountered, and general safety considerations to protect personnel, equipment, and the environment. Date andtime 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


### 210 30 CFR Ch. II (7–1–13 Edition) § 250.1623

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 H 2 S or zones where the presence of H 2 S is unknown, a descriptionof 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 monitoredduring 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 fluidequipment 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 withdrill 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 postednear the operator’s station. A mechanical, volumetric, or electronic devicefor 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


### 211 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 200psi above the precharge pressure without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air which donot 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 powersource 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 controlledexcept 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 performedthrough the wellhead inside of the sulphur line using small diameter jointed pipe (usually 3 ⁄ 4 inch to 1 1 ⁄ 4 inch) as a work string; i.e., small-tubing operations, shall consist of the following:

(1) For air line changes, the wellshall be killed prior to beginning operations. The procedures for killing thewell 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 shallbe 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 bepressure 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 safetyvalves shall be pressure tested to piperam test pressures. Safety valves withproper 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 pressuretests, 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 morethan 7 days between BOP tests is allowed when there is a stuck drill pipeor 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


### 212 30 CFR Ch. II (7–1–13 Edition) § 250.1626

testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressuretest 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 pressureconditions during BOP tests on pressure charts, unless otherwise approvedby 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 certifiedas 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 indicatethe 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 BOPtest plan that contains the required information and is retained on file at the facility.

(2) The control station used duringthe 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 yearsat 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 toassure 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 facilitiesshall 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


### 213 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 fieldoffice 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 allowableworking 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 classifiedaccording 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 systemsto 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 systemwith 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 ofBasic Surface Safety Systems for Offshore Production Platforms (as incorporated by reference in §250.198). Ifprocessing 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 designand installation features for fuel gas system. Prior to installation, the lessee shall submit a fuel gas safety systemapplication, 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 fieldoffice 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 allowableworking pressures as determined in accordance with API RP 14E, Design and
Installation of Offshore ProductionPlatform 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


### 214 30 CFR Ch. II (7–1–13 Edition) § 250.1629

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 schematicof any platform safety shutdown system with a functional legend.

(5) Certification that the design for the mechanical and electrical systemsto 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 thedetection 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 operationof additional production systems, including fuel gas handling safety systems. (1)
Pressure and fired vessels must be designed, fabricated, and code stamped inaccordance with the applicable provisions of sections I, IV, and VIII of theAmerican 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 APIPressure 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 maintainedin accordance with applicable provisions of sections I, IV, and VIII of the
ANSI/ASME Boiler and Pressure VesselCode (as specified in §250.198). The safety relief valves shall conform to thevalve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valvesshall 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 orderto establish the pressure-sensor settings. Pressure-recording charts used to determine operating pressure ranges shall be maintained by the lessee for aperiod of 2 years at the lessee’s field office nearest the OCS facility or at another location conveniently availableto the District Manager. The high-pressure sensor shall be set no higher than15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shallalso be set sufficiently below (15 percent or 5 psi, whichever is greater) thesafety 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 equipengine 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


### 215 Safety & Environmental Enforcement, Interior § 250.1630

Prevention and Control on Open TypeOffshore Production Platforms (as incorporated by reference in §250.198), and must be subject to the approval ofthe 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 shallbe 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 firefightingsystem 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 chemicalsystem 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 ventilationthat 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 bywalls, 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 theguidelines 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 ofAPI 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 levelsshall 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 classifiedarea do not require a gas detection system.

(iv) The District Manager may require the installation and maintenanceof 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 theperson 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


### 216 30 CFR Ch. II (7–1–13 Edition) § 250.1631

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 naturalgas feed system for power plant operations such as pressure safety valvesshall 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 providedthat 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 DistrictManager 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 OCSfacility 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 anddetails of installation, removal, inspection, testing, repairing, adjustments,
and reinstallation.

§ 250.1631 Safety device training.

Prior to engaging in production operations on a lease and periodicallythereafter, personnel installing, inspecting, testing, and maintaining safety devices shall be instructed inthe 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 safetymeetings 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 wouldmaximize the ultimate recovery of sulphur without resulting in waste (e.g., an undue reduction in the recovery ofoil and gas from an associated hydrocarbon accumulation).

§ 250.1633 Production measurement.

(a) General. Measurement equipmentand security procedures shall be designed, installed, used, maintained, andtested so as to accurately and completely measure the sulphur producedon a lease for purposes of royalty determination.

(b) Application and approval. The lessee shall not commence production of sulphur until the Regional Supervisorhas approved the method of measurement. The request for approval of the
method of measurement shall contain
sufficient information to demonstrateto 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


### 217 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 afterdiscovery of the evidence of mishandling.



### Subpart Q—Decommissioning Activities

G ENERAL

§ 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 ofBSEE and other agencies that have jurisdiction over decommissioning activities.

(b) Obstructions mean structures, equipment, or objects that were used inoil, 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, casingstubs, mud line suspensions, well protection devices, subsea trees, jumperassemblies, 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 includeproduction and pipeline risers, templates, pilings, and any other facilityor 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 operatingrights 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 meetingdecommissioning obligations for facilities on their right-of-way, includingright-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 toright-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 thissubpart, 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 appropriateDistrict Manager before decommissioning wells and from the Regional Supervisor before decommissioning


### 218 30 CFR Ch. II (7–1–13 Edition) § 250.1704

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 tothe 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.

D ECOMMISSIONING A PPLICATIONS AND R EPORTS T ABLE

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 least2 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 yearsafter 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


### 219 Safety & Environmental Enforcement, Interior § 250.1706

pods, location of choke and kill lines, and associated valves;

(c) Independent third-partyverification and supporting documentation that show the blind-shearrams installed in the BOP stack are capable of shearing any drill pipe (including workstring and tubing) in the hole under maximum anticipated surfacepressure. The documentation must include actual shearing and subsequent pressure integrity test results for themost rigid pipe to be used and calculations of shearing capacity of all pipe tobe 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 inthis section is a technical classification society, or a licensed professionalengineering 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 toperform 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 thelocation to witness any testing or inspections, and verify information submitted to BSEE. Prior to any shearingram 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 towhich 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 thewell abandonment operations, a wellcontrol procedure that indicates how the annular preventer will be utilized, and the pressure limitations that willbe applied during each mode of pressure control.

(b) The minimum BOP system for well abandonment operations with thetree 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.


### 220 30 CFR Ch. II (7–1–13 Edition) § 250.1706

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 200psi 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 thecheck 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 ofconventional tubing using small-diameter jointed pipe (usually 3 ⁄ 4 inch to
1 1

⁄ 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 mustmeet 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.


### 221 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 thecoiled tubing string for all coiled tubing well abandonment operations. If you plan to conduct operations withoutdownhole check valves, you must describe alternate procedures and equipment in Form BSEE–0124, Applicationfor 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 equalto or greater than the working pressure rating of the connection to whichthey are attached, and you must install them between the well-control
stack and the choke or kill line. Foroperations 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 sufficientaccumulator capacity to close-openclose each component in the BOP stack. This cycle must be completedwith 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 beflanged, 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 piperams 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 alltimes during well abandonment operations when the tree is removed or during well abandonment operations withthe 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 insertingvalves 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 requirementsfor blowout preventer system testing, records, and drills?

(a) BOP pressure tests. When you pressure test the BOP system, you mustconduct a low-pressure test and a highpressure test for each component. Youmust 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 andkill 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 ofthe BOP equipment, or as otherwise approved by the BSEE District Manager.


### 222 30 CFR Ch. II (7–1–13 Edition) § 250.1707

You must successfully test the annular-type BOP at 70 percent of its ratedworking 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 sizesof 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, alternatingbetween control stations and at staggered intervals to allow each crew tooperate 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 atleast once every 30 days during operation. A longer period between blowout preventer tests is allowed when there isa stuck pipe or pressure-control operation and remedial efforts are beingperformed. The tests must be conducted as soon as possible and before normal operations resume. The reason for postponing testing must be enteredinto 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 wellabandonment operations must participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.

(d) You may conduct a stump test forthe 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 tothe 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, expectedsurface pressure, or the collapse pressure of the coiled tubing, whichever is
less.

(f) You must record test pressures during BOP and coiled tubing tests ona pressure chart, or with a digital recorder, unless otherwise approved by the BSEE District Manager. The testinterval for each BOP system component must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure testfor 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 indicatethe 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 testplan that contains the required information and is retained on file at the facility.

(2) The control station used duringthe test must be identified in the operations log. For a subsea system, thepod 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, youmust retain all such records for a period of two years at the facility, at the


### 223 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 mayuse 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 arefunction 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 theseafloor 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 yourAPM for BSEE District Manager approval. The procedures for these function tests must include documentationof 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 RP53, Recommended Practices for Blowout Prevention Equipment Systems forDrilling Wells (incorporated by reference as specified in §250.198). Youmust 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 toBSEE 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 seaconditions permit. You may use television cameras to inspect this equipment. The BSEE District Manager mayapprove 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 17.12and 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 recordsare created, or for a longer period if directed by BSEE.

[77 FR 50900, Aug. 22, 2012]


### 224 30 CFR Ch. II (7–1–13 Edition) § 250.1709

§ 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 obtainapproval 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 willsafely 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]

P ERMANENTLY P LUGGING W ELLS

§ 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 operationsand 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 Managerand 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 theRegional Supervisor, along with substantiating information demonstratingits 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 theplugging 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 thetable in §250.1715. In addition to the requirements of §250.1715, the Registered Professional Engineer must also certify the design will include two independentbarriers, one of which must be a mechanical barrier, in the center wellboreas described in §250.420(b)(3). The Registered Professional Engineer must be registered in a State of the United States and have sufficient expertise


### 225 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.

P ERMANENT W ELL P LUGGING R EQUIREMENTS

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.


### 226 30 CFR Ch. II (7–1–13 Edition) § 250.1716

P ERMANENT W ELL P LUGGING R EQUIREMENTS —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 erosionalprocesses 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 awell, what information must I submit?

Within 30 days after you permanently plug a well, you must submit form BSEE–0124, Application for Permit toModify (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.

T EMPORARY A BANDONED W ELLS

§ 250.1721 If I temporarily abandon a well that I plan to re-enter, what must I do?

You may temporarily abandon a wellwhen 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). Youdo 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


### 227 Safety & Environmental Enforcement, Interior § 250.1722

1,000 feet below the mud line. BSEEmay consider approving alternate requirements for subsea wells case-bycase;

(e) Identify and report subseawellheads, 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 submitform 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 thewell abandonment design and procedures and that all plugs meet the requirements of paragraph (b) of this section. In addition to the requirements ofparagraph (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 fishinggear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.

(a) Use form BSEE–0124, Applicationfor 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 theseafloor (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 causesdamage to it, you must notify the appropriate District Manager within 5days and perform remedial action within 30 days of the trawl;

(d) Within 30 days after you completethe 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 ofany 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


### 228 30 CFR Ch. II (7–1–13 Edition) § 250.1723

(6) A letter signed by your authorizedrepresentative 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 workwithin 30 days of discovery of the problem.

(3) In your annual report required by paragraph (f) of this section, includethe 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 bytrawl 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 awell 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 mustsubmit 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.

R EMOVING P LATFORMS AND O THER F ACILITIES

§ 250.1725 When do I have to remove platforms and other facilities?

(a) You must remove all platforms and other facilities within 1 year afterthe lease or pipeline right-of-way terminates, unless you receive approval to
maintain the structure to conductother activities. Platforms include production platforms, well jackets, singlewell caissons, and pipeline accessory platforms. Other activities includethose supporting OCS oil and gas production and transportation, as well as other energy-related or marine-relateduses (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 timefollowing 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


### 229 Safety & Environmental Enforcement, Interior § 250.1727

include the information listed in §250.1727.

(c) You must remove a platform orother 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 andthe 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 otherfacility. Your application must be accompanied by payment of the servicefee 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 acousticdevices to conduct a pre-removal survey to detect the presence of turtles


### 230 30 CFR Ch. II (7–1–13 Edition) § 250.1728

and marine mammals, a description of the proposed detection method; and

(4) A statement whether or not you
will use transducers to measure thepressure 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 mustremove 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 erosionalprocesses 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 mustsubmit 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 certifiesthat the types and amount of explosives you used in removing the platform or other facility were consistentwith those set forth in the approved removal application.

§ 250.1730 When might BSEE approvepartial structure removal or toppling in place?

The Regional Supervisor may grant adeparture 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 ofEngineers 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 UseRUE 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 willremain responsible for decommissioning obligations that accrued before issuance of the Alternate Use RUE, aswell as for decommissioning obligations that accrue following issuance of
the Alternate Use RUE to the extent
associated with continued activities authorized under this part.


### 231 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 togrant such a deferral, the lessee remains responsible for removing the facility upon termination of the Alternate Use RUE and will be required toretain sufficient bonding or other financial assurances to ensure that the
structure is removed or otherwise decommissioned in accordance with the provisions of this subpart.

S ITE C LEARANCE FOR W ELLS

, P LATFORMS

, AND O THER F ACILITIES

§ 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 bythe 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 becleared as a hazard to navigation according to USCG requirements untilyou complete the site clearance procedures.

(d) You must use a trawling vesselequipped 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 trawlno 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 thepipeline before trawling over the buried pipeline.


### 232 30 CFR Ch. II (7–1–13 Edition) § 250.1742

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 trawlinglicense 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 canverify 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 recordsvideotape 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 astatement 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 facilitysite, 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 astatement from the trawling contractor that no objects were recovered;
and

(7) A post-trawling job plot or map showing the trawled area.


### 233 Safety & Environmental Enforcement, Interior § 250.1900

P IPELINE D ECOMMISSIONING

§ 250.1750 When may I decommission a pipeline in place?

You may decommission a pipeline inplace when the Regional Supervisor determines that the pipeline does not constitute a hazard (obstruction) tonavigation and commercial fishing operations, unduly interfere with otheruses 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 concretemats, if required by the Regional Supervisor; and

(g) Remove all pipeline valves andother 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 briefassessment 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 awritten 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.


### 234 30 CFR Ch. II (7–1–13 Edition) § 250.1901

Your SEMS program must address theelements described in §250.1902, American Petroleum Institute’s Recommended Practice for Development ofa Safety and Environmental Management Program for Offshore Operationsand 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 affectssafety 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 topromote 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 mustensure that your SEMS program identifies, addresses, and manages safety, environmental hazards, and impactsduring the design, construction, startup, operation (including, but not limited to, drilling and decommissioning), inspection, and maintenance of all newand 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 andmake 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 safetyanalysis (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,


### 235 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 aBSEE-approved independent thirdparty organization that assesses and
accredits ASPs.

Audit Service Provider (ASP) means an independent third-party organizationthat 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 individualor 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, eachand 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 forreporting 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 thepossible 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.


### 236 30 CFR Ch. II (7–1–13 Edition) § 250.1910

(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 inidentifying 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 impactsis an integral part of the design, construction, maintenance, operation, and monitoring of each facility.

(i) Ensure that suitably trained and qualified personnel are employed tocarry out all aspects of the SEMS program.

(j) Ensure that the SEMS program is maintained and kept up to date bymeans 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 thebasis 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 areaclassifications; 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 ensurethat 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, andmanage 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 requirementsfor simple and nearly identical facilities, such as well jackets and single


### 237 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 areaddressed 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 usedto determine the appropriate mitigation measures needed to reduce jobrisks 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 aworkplace injury or illness, or environmental impacts.

(2) The immediate supervisor of the crew performing the job onsite mustconduct the JSA, sign the JSA, and ensure that all personnel participating in the job understand and sign the JSA.

(3) The individual you designate asbeing 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 jobmay decide that a JSA for each individual job is not required. The parameters you must consider in making thisdetermination 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 implementwritten 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 proceduresdo 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 achange in the operation, must be informed of, and trained in, the changeprior 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 implementwritten operating procedures that provide instructions for conducting safe and environmentally sound activities involved in each operation addressed in your SEMS program. These proceduresmust 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;


### 238 30 CFR Ch. II (7–1–13 Edition) § 250.1914

(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 stepsrequired 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 theenvironment. 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 specifiedperiods 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 establishand 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 thecontractor’s safety record and environmental performance. You must ensure
that contractors have their own written safe work practices. Contractors may adopt appropriate sections of yourSEMS 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, theserequirements do not apply to contractors providing domestic services to you
or other contractors. Domestic servicesinclude janitorial work, food and beverage service, laundry service, housekeeping, and similar activities.

(b) You must document that yourcontracted employees are knowledgeable and experienced in the work practices necessary to perform their job ina safe and environmentally sound manner. Documentation of each contracted employee’s expertise to perform his/herjob 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 includeprocedures and verification for selecting a contractor as follows:

(1) Your SEMS program must have procedures that verify that contractorsare conducting their activities in accordance with your SEMS program.

(2) You are responsible for making
certain that contractors have the skillsand 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 ofyour verification for selecting contractors available to BSEE upon request.

(d) Your SEMS program must includeprocedures and verification that contractor personnel understand and canperform their assigned duties for activities such as, but not limited to:


### 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 employeeinjury and illness log for 2 years related to the contractor’s work in theoperation 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 implementsafe 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 sothat 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 ofthe environment, and ensure that persons assigned to operate and maintainthe 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, usingperiodic 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/ornotice 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 implementwritten procedures that provide instructions to ensure the mechanical integrity and safe operation of equipment through inspection, testing, andquality assurance. The purpose of mechanical integrity is to ensure thatequipment is fit for service. Your mechanical integrity program must encompass all equipment and systemsused 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 andsystems 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 employeescan implement your mechanical integrity program.

(c) The frequency of inspections and tests of your equipment and systems. The frequency of inspections and tests


### 240 30 CFR Ch. II (7–1–13 Edition) § 250.1917

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 performedthe inspection or test; include the serial number or other identifier of the equipment on which the inspection ortest 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 equipmentand constructing systems. The procedures must address the application for which they will be used.

(g) The modification of existingequipment and systems. The procedures must ensure that they are modified for the application for which they
will be used.

(h) The verification that inspectionsand tests are being performed. The procedures must be appropriate to ensurethat 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 environmentalreview for new and significantly modified facilities that are subject to this subpart to confirm that the following
criteria are met: (a) Construction and equipment arein 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 controlplans 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 afacility for initiating effective emergency response and control, addressingemergency 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 scenariosconducted periodically to exercise elements contained in the facility or area emergency action plan. An analysisand critique of each drill must be conducted to identify and correct weaknesses.


### 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 ofincidents that are determined by facility management or BSEE to have possessed the potential for serious safetyor environmental consequences. Incident investigations must be initiatedas 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 auditteam lead must be an employee, representative, or agent of the ASP, and must not have any affiliation with theoperator. 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. Itmust 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) andinclude 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 asdescribed in §250.1921. You must include the ASP’s qualifications in your audit plan.

(c) You must submit an audit reportof the audit findings, observations, deficiencies identified, and conclusions toBSEE within 60 days of the audit completion date.

(d) You must provide BSEE with acopy 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 responsiblefor correcting the identified deficiency(ies). The BSEE will notify you as soon as practicable after receipt of your CAP if your proposed schedule is


### 242 30 CFR Ch. II (7–1–13 Edition) § 250.1921

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 thequalifications, competency, and training criteria contained in Section 3 and Sections 6 through 10 of Qualification and Competence Requirements for AuditTeams 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 therequirements 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; CorrectedVersion 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 AuditService 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. Organizationsrequesting approval must submit documentation to BSEE describing theprocess for assessing an ASP for accreditation and approving, maintaining, and withdrawing the accreditation of an ASP. Requests for approval mustbe 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 asoutlined 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 ifBSEE identifies safety or non-compliance concerns based on the results of our inspections and evaluations, or as a


### 243 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 reportof the audit findings, observations, deficiencies identified, and conclusions toBSEE within 60 days of the audit completion date.

(2) If BSEE conducts the audit, BSEE will provide you with a report of theaudit findings, observations, deficiencies identified, and conclusions as soon as practicable.

(b) You must provide BSEE a copy ofyour CAP for addressing the deficiencies identified in the BSEE-directed audit within 60 days of the auditcompletion 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 practicableafter 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 findsshortcomings 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. Youmust 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/illnesslog for 2 years and make them available to BSEE upon request.

(e) You must keep all evaluationscompleted on contractor’s safety policies and procedures for 2 years andmake 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.


### 244 30 CFR Ch. II (7–1–13 Edition) § 250.1930

§ 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 riskor 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 theindividual on the facility with UWA determines that the imminent risk ordanger 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 proceduresand expectations as a standard statement in all JSAs.

(e) You must conduct training onyour SWA procedures as part of orientations for all new personnel whoperform 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 takinginto 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. Inthe event that multiple facilities, including a MODU, are attached and working together or in close proximityto one another to perform an OCS operation, your SEMS program must identify the individual with the UWA overthe 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 providethat if an emergency occurs that creates an imminent risk or danger to the health or safety of an individual, thepublic, 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 consultwith 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 bothyour offices and those working on offshore facilities, will participate in yourSEMS program development and implementation.

(c) Your management must ensure that employees have access to sectionsof your SEMS program that are relevant to their jobs.

[78 FR 20443, Apr. 5, 2013]

§ 250.1933 What procedures must beincluded for reporting unsafe working conditions?

(a) Your SEMS program must include procedures for all personnel to reportunsafe working conditions in accordance with §250.193. These procedures must take into account applicableUSCG reporting requirements for unsafe working conditions.

(b) You must post a notice at theplace of employment in a visible location frequently visited by personnel


### 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.

A UTHORITY : 31 U.S.C. 9701, 43 U.S.C. 1334.

S OURCE : 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 mayinclude, 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 descriptionsof 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 orscholarly 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 thatinteractively 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 adjacentshorelands (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 notbeen 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 commercialsearch 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 orimply 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 theOCS for scientific and/or research purposes. Geological, geophysical, and geochemical data and informationgathered 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 bottomsampling) to produce data and information on oil, gas, and sulphur resources in support of possible exploration and