[Federal Register Volume 65, Number 120 (Wednesday, June 21, 2000)]
[Proposed Rules]
[Pages 38453-38474]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-15546]


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DEPARTMENT OF THE INTERIOR

Minerals Management Service

30 CFR Part 250

RIN 1010-AC43


Oil and Gas and Sulphur Operations in the Outer Continental 
Shelf--Oil and Gas Drilling Operations

AGENCY: Minerals Management Service (MMS), Interior.

ACTION: Proposed rule.

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SUMMARY: This proposed rule restructures the requirements for oil and 
gas drilling operations on the Outer Continental Shelf (OCS), adds some 
new requirements, and converts the rule into plain language. The 
proposed rule follows the logical sequence of obtaining approval to 
drill a well and conducting operations. The proposed rule also removes 
overly prescriptive requirements and updates requirements to reflect 
changes in drilling technology. Restructuring the drilling requirements 
will make the regulations easier to read, understand, and follow. The 
proposed technical changes will help ensure that lessees conduct 
operations in a safe manner.

DATES: MMS will consider all comments we receive by September 19, 2000. 
We will begin reviewing comments then and may not fully consider 
comments we receive after September 19, 2000.

ADDRESSES: Mail or hand-carry comments to the Department of the 
Interior; Minerals Management Service; Mail Stop 4024; 381 Elden 
Street; Herndon, Virginia 20170-4817;

[[Page 38454]]

Attention: Rules Processing Team (Comments).
    Mail or hand-carry comments with respect to the information 
collection burden of the proposed rule to the Office of Information and 
Regulatory Affairs; Office of Management and Budget; Attention: Desk 
Officer for the Department of the Interior (OMB control number 1010-
NEW); 725 17th Street, NW., Washington, DC 20503.

FOR FURTHER INFORMATION CONTACT: Bill Hauser, Engineering and 
Operations Division, at (703) 787-1600.

SUPPLEMENTARY INFORMATION: This proposed revision of Subpart D, Oil and 
Gas Drilling Operations, contains several changes from the current 
regulations. One major change is the organization of the subpart. We 
have moved the Application for Permit to Drill (APD) section into the 
front of the subpart, where it becomes the cornerstone of the drilling 
requirements. The other sections follow in a logical sequence. The last 
major revision to the drilling regulations occurred on April 1, 1988 
(53 FR 10596), when MMS consolidated the OCS Orders and the regulations 
into a single package. We welcome comments on the order of the 
sections.
    The proposed rule uses several methods to put MMS's drilling 
requirements in plain language. These methods include:
    <bullet> Breaking down lengthy sections into multiple sections;
    <bullet> Using lists in place of lengthy paragraphs;
    <bullet> Moving and consolidating similar requirements into single 
sections;
    <bullet> Using tables where possible (such as casing and cementing 
requirements);
    <bullet> Removing overly prescriptive requirements;
    <bullet> Using ``you'' to refer to the lessee, operator, or person 
acting on behalf of a lessee; and
    <bullet> Using questions as section titles.
    We encourage your comments on any of these innovations.
    The rule also proposes some new requirements. MMS District 
Supervisors and Drilling Engineers recommended most of the new proposed 
requirements based on their experience of reviewing and approving 
Applications for Permit to Drill and other drilling operations. Some of 
the new requirements will improve the flow of information between the 
lessee and the Drilling Engineer reviewing a request (such as listing 
all departures in one place as required in Sec. 250.418(g)) or will 
fill a gap in the current regulations (such as recordkeeping for casing 
tests in Sec. 250.428). The following paragraphs identify and briefly 
discuss the most important proposed revisions. We welcome your comments 
on these proposed requirements.

Rig Move Notification (Sec. 250.404)

    The proposed rule would require the lessee to notify the District 
Supervisor 24 hours before rig arrival on and departure from the well 
location. MMS needs to know the comings and goings of drilling rigs to 
effectively and efficiently schedule inspections of drilling 
operations. MMS has attached this requirement as a condition of 
approval to APDs for many years. This would now make this condition of 
approval part of the regulations.

New Form To Supplement the APD Information (Sec. 250.410)

    The proposed rule requires a lessee to use the new form MMS-123-
Supplemental APD Information Sheet. The new form provides MMS drilling 
engineers with a technical summary of the information required in the 
APD. This aids District offices in the efficient review and approval of 
APDs. We also believe the successful use of this form helps pave the 
way for future electronic submissions of APDs.
    The Office of Management and Budget has approved the new form, 
which does not require any new information. For further information 
about this form, you may contact Bill Hauser or Alexis London with the 
Rules Processing Team at 703-787-1600.

Well Location Description (Sec. 250.412)

    The proposed rule requires the lessee to provide a more precise 
description of the surface and subsurface locations of the proposed 
well. The current regulations require lessees to provide the location 
in feet from the block line, but there has been a longstanding problem 
for computer routines that convert distances from block lines to x-y 
and longitude-latitude coordinates for well locations in irregular 
blocks. The x-y and longitude-latitude coordinates will be more 
accurate, allow easier data entry, and be more compatible for mapping.

Requests for Using Alternative Procedures or Departures from the 
Regulations (Sec. 250.418(g))

    The proposed rule requires the lessee to list and discuss all 
requests for using alternative procedures or departures from the 
regulations in one place within the APD. This will aid District offices 
in the review and approval of these requests and the APD. The proposed 
rule requires you to explain how the alternative procedure affords an 
equal or greater degree of protection, safety, or performance or why 
you need the departure.

Waiting on Cement (Sec. 250.422(b))

    The proposed rule requires that the lessee must determine when it 
is safe to nipple down (remove) the diverter or blowout preventer (BOP) 
stack after cementing a casing string. MMS proposes this new 
requirement because there have been some cases where a blowout occurred 
after a lessee nippled down the diverter or BOP stack while waiting on 
cement. We considered setting a specific waiting time or a compressive 
strength for the cement but decided that the complexity of cementing 
operations and variety of cements are not good candidates for a 
prescriptive requirement. The proposed rule makes the lessee 
responsible for evaluating the factors associated with each cement job 
to determine when it is safe to nipple down the diverter or BOP stack.
    Currently, MMS requires the lessee to hold the cement in newly 
cemented casing strings under pressure for 8 hours for conductor casing 
or 12 hours for other casing strings before resuming drilling. It is 
during these waiting times that the lessees usually nipple down and 
nipple up (install) the diverter or BOP stack. The proposed rule does 
not revise or remove these waiting times. These required waiting times 
help ensure that the cement attains sufficient strength to safely 
resume drilling. Your comments on this approach to addressing this 
issue are welcomed.

Best Cementing Practices

    The current drilling requirements do not address the methods you 
must use to cement casing strings. MMS has allowed lessees to use their 
judgment in selecting the proper method of cementing casing and liners. 
While this approach has worked for the successful drilling and 
completion of wells, we are less convinced that this approach has been 
successful for the long-term life of many wells. MMS believes that poor 
cementing practices are among the main primary causes of sustained 
casing pressures on producing wells. As a preventive measure to reduce 
the number of wells with sustained casing pressures, we recommend that 
lessees use better cementing practices for production wells. This is 
especially true with subsea wells where it is not possible to monitor 
most casing pressures. We welcome your comments on the use of improved 
cementing practices to address some of the problems associated with 
sustained casing pressures.

[[Page 38455]]

Minimum Cemented Casing Strings for Producing Wells 
(Sec. 250.423(f))

    The proposed rule requires that you must have at least two cemented 
casing strings if you plan to produce the well. This has been an 
unwritten rule for OCS wells in the Gulf of Mexico Region (GOMR) for 
many years. MMS believes that two cemented casing strings (not 
including any cemented liners) are the minimum needed to ensure safe 
production for the life of the well. This proposed requirement makes 
this unwritten requirement available for comment.

Recordkeeping for Casing, Liner, and Diverter Pressure Tests 
(Secs. 250.427 and 250.434)

    The proposed rule clarifies what MMS has expected a lessee to 
record for casing, liner, and diverter pressure tests. The casing 
pressure test must be recorded on a pressure chart and certified by 
your onsite representative as being correct. The time, date, and 
results are then recorded in the driller's report. Recordkeeping 
requirements for a diverter test are similar to those required for a 
BOP test.

Blind-shear Ram for Surface BOP Systems (Secs. 250.441, 250.515(b), 
and 250.615(b))

    The proposed rule requires a lessee to install a blind-shear ram in 
the surface BOP stack instead of a blind ram. MMS believes that a 
blind-shear ram in the surface stack provides an additional safety 
measure in handling well control events. We recently reviewed the 
blowouts that have occurred since 1977 and found at least 12 incidents 
where a blind-shear ram had helped or could have helped control the 
situation. These blowouts usually occurred when drill pipe or tubing 
was hung in the BOP stack, and there were difficulties in installing or 
closing a drill string safety valve, inside the BOP, or tubing safety 
valve. Several of these blowout events had major casualties and/or 
damage to platforms and drilling rigs.
    MMS believes that the use of blind-shears rams will prevent or 
minimize some blowouts on the OCS. This would reduce the risk of injury 
and loss of life to personnel and the risk of environmental damages 
from a blowout. We believe the benefits from reduced injuries, 
fatalities, environmental damages, and losses from property damages 
will easily out weigh the costs of installing the blind-shear rams. 
This measure is consistent with our Congressional mandate to prevent or 
minimize the likelihood of blowouts (OCS Lands Act at 43 U.S.C. 
1332(6)).
    MMS believes that the installation of a blind-shear ram in BOP 
stacks should also be applied to completion and workover operations 
because several of the above blowout events involved completions and 
workovers. The proposed rule does not apply to workovers with the tree 
in place. The proposed rule also revises Sec. 250.515(b) and 
Sec. 250.615(b).
    The proposed rule provides for a 1-year grace period to comply with 
the requirement to install a blind-shear ram on surface stacks. Lessees 
will have 1 year from the effective date of the final rule to install 
blind-shear rams in all surface BOP stacks.

Reference Minimum Accumulator Requirements for Subsea BOP Systems 
(Sec. 250.442)

    The proposed rule references section 12.3, Accumulator Volumetric 
Capacity, in the American Petroleum Institute's Recommended Practice 
for Blowout Prevention Equipment Systems for Drilling Wells (API RP 
53). We included this reference so that both industry and MMS would 
have guidelines for determining the minimum requirements and 
performance for subsea accumulators and BOP systems. Included in this 
section are minimum accumulator response times for annular and ram 
preventers. The proposed rule also requires the lessee to record the 
closing times for subsea annular and ram preventers. These proposed 
revisions will help ensure that subsea BOP systems operate at proper 
levels of performance.

Reference Minimum BOP Maintenance Requirements (Sec. 250.446)

    The current regulations in Sec. 250.407 require the lessee to 
maintain BOP equipment to ensure that it operates properly. The 
proposed rule goes on to require that this maintenance must meet or 
exceed the provisions of sections 17.10 and 18.10 (Inspections); 
sections 17.11 and 18.11 (Maintenance); and sections 17.12 and 18.12 
(Quality Management), in API RP 53. MMS selected API RP 53 as the 
standard to use because it represents a composite of the practices used 
by various operators and drilling contractors.
    The importance of a thorough maintenance program is even greater 
now that MMS has allowed lessees to test BOP equipment less frequently 
than before (see final rule for BOP testing published June 1, 1998, 63 
FR 29604). MMS believes that maintenance is critical to the proper 
operation of BOP equipment. MMS considered including specific 
maintenance practices when we revised the BOP testing requirements but 
decided to limit that rulemaking to the BOP testing issue since the BOP 
performance study did not specifically address BOP maintenance. This 
rulemaking would set those minimum requirements.
    The proposed rule references only specific sections of API RP 53. 
We have referenced specific sections because these were the most 
critical areas of concern. However, several industry commenters on the 
BOP testing requirements recommended incorporating the entire API RP 53 
document. We would like your comments on whether MMS should reference 
specific sections or incorporate the entire document into the 
regulations.

Use of Maximum Anticipated Surface Pressure (MASP) for Determining 
BOP Test Pressures (Sec. 250.448)

    As discussed in the preambles of the proposed (July 15, 1997, 62 FR 
37819) and final rules for BOP testing requirements, MMS has considered 
using MASP in determining BOP test pressures. Industry comments on the 
proposed BOP testing rule showed interest in this approach for 
determining test pressures, but both industry and MMS expressed 
concerns about how to calculate MASP. After considerable thought, MMS 
has decided to propose using MASP calculations in determining BOP test 
pressures. Under the proposed rule, the high pressure test must either 
equal the rated working pressure of the equipment, or be 500 pounds per 
square inch (psi) greater than the calculated MASP for the applicable 
section of hole, whichever is smaller. This reflects how MMS currently 
reviews and approves test pressures. It is also consistent with current 
industry practice of testing BOPs at less than the rated working 
pressures. The proposed rule also clearly states that the District 
Supervisor must have approved the MASP plus 500 psi test pressures in 
the APD.
    Currently, District Supervisors base the approval of alternate test 
pressures on a comparison of the anticipated surface pressure 
calculations submitted with the APD to MASP calculations made by MMS 
drilling engineers. If the two calculations compare favorably, the 
District Supervisor approves the requested test pressures. If the 
calculations for anticipated surface pressure are less than those 
calculated by MMS, the District Supervisor advises the lessee of any 
necessary revisions to the APD.

[[Page 38456]]

Change in Terminology--Mud to Drilling Fluid

    The proposed rule changes the term ``mud'' as in drilling mud to 
``drilling fluid.'' We believe that this change more accurately 
reflects the current terminology. We have changed the term ``mud'' to 
``drilling fluid'' throughout subpart D. We will make the same change 
in other subparts as we revise them.

Posting Maximum Safe Pressures Contained Under a Shut-In BOP 
(Sec. 250.456(f))

    The proposed rule clarifies the current requirement of posting the 
maximum pressure that you may safely contain under a shut-in BOP for 
each casing string. The proposed rule requires the posting of two 
pressures: (1) the surface pressure at which the casing shoe would 
break down and, (2) the lesser of the BOP's rated working pressure or 
70 percent of casing burst pressure (or casing test pressure otherwise 
approved by the District Supervisor). The current requirement has led 
to some confusion as to what safe pressure MMS wants posted, i.e., 
formation fracture pressure or equipment limitation pressure. By having 
both pressures posted, the driller will have additional information 
immediately available for decisionmaking.

Establish Well Testing Requirements (Sec. 250.460)

    The proposed rule establishes minimum requirements for well-testing 
activities. Currently there are no regulations that specifically 
address well testing. MMS believes that minimum requirements are 
necessary to understand and evaluate the lessee's anticipated well-
testing activities. The proposed rule would require a lessee to submit 
information about testing procedures and equipment to the District 
Supervisor for approval with the APD or a Sundry Notice. You would not 
be allowed to conduct the well test until the District Supervisor 
approves the submitted test information. The information that must be 
submitted includes estimated flowing and shut-in tubing pressures; 
estimated flow rates and cumulative volumes; time duration of flow, 
buildup, and drawdown periods; a description of surface and subsurface 
test equipment; proposed methods to handle or transport produced 
fluids; and a full description of the test procedures.

Simplify Survey Requirements for Directional Drilling 
(Sec. 250.461)

    The proposed rule simplifies the language and the requirements to 
be consistent with current practices and technology. The proposed rule 
also makes these survey requirements a separate section.

Hydrogen Sulfide (Sec. 250.470)

    The hydrogen sulfide section of subpart D was not revised. We are 
not revising this section now because it was revised in January 1997 
(62 FR 3795). MMS will consider revising this section as we begin the 
rewriting of subpart E, Oil and Gas Well-Completion Operations; subpart 
F, Oil and Gas Well-Workover Operations; and subpart H, Oil and Gas 
Production Safety Systems. Your comments on the best method to rewrite 
or reorganize the hydrogen sulfide requirements are welcomed.

Requirements Removed From Subpart D

    The proposed rule does not contain requirements for the welding and 
burning practices and procedures (former Sec. 250.402) or electrical 
equipment (former Sec. 250.403). These requirements were moved to 
subpart A of the regulations in the Notice of Final Rulemaking for 
subpart A, which was published in the Federal Register on December 28, 
1999 (64 FR 72756).
    The proposed rule also removes the detailed well-control drill 
requirements. These requirements (current Sec. 250.408) prescribe how 
the lessee is to conduct the drill. MMS proposes to remove these 
requirements because they are too prescriptive. MMS still would require 
the lessee to outline the assignments for each member of the drilling 
crew.

Other Considerations for Drilling Regulations

    MMS also considered including regulations for drilling with coiled 
tubing units in this revision of subpart D. However, we decided to 
postpone proposing requirements for coiled tubing drilling operations 
until MMS has a better understanding of these operations and the amount 
of activity that will likely take place on the OCS. MMS would most 
likely use API's Recommended Practice for Coiled Tubing Operations in 
Oil and Gas Well Services (API RP 5C7) as a guideline when we do 
propose appropriate regulations. We would like your comments on the 
need for regulations for coiled tubing drilling.
    MMS is also looking at requiring drilling rigs to use automated 
pipe handling systems during drilling operations. MMS believes that the 
use of automated pipe handling systems clearly provides safety 
advantages over non-automated pipe handling systems. After further 
consultation with the U.S. Coast Guard, we may propose this new 
requirement under the provision in Sec. 250.107, which mandates that 
the Director require the use of the best available and safest 
technology to protect health, safety, property, and environment. We 
welcome your comments on requiring automated pipe handling systems as 
well as your comments on the best approach to implementing this 
requirement.

Derivation Table

    The derivation table below shows where the proposed requirements 
come from in relation to the current sections. The table also provides 
the section numbers that were used from 1988 up until mid-1998 when MMS 
assigned new numbers to the sections to aid in the updating and 
revision of the regulations (63 FR 29478, May 29, 1998).

                            Derivation table
------------------------------------------------------------------------
  Proposed new section and
            title             Current section  Previous numbering system
------------------------------------------------------------------------
250.400  Who is subject to    New section....  New section.
 the requirements of this
 subpart?
250.401  What must I do to    250.400........  250.50.
 keep wells under control?
250.402  When and how must I  250.411........  250.61.
 secure a well?
250.403  What safety          250.401........  250.51.
 requirements must my
 drilling unit meet?
250.404  What mobile          New requirement  New requirement.
 drilling unit movements
 must I report?
250.410  How can I apply for  250.414(a).....  250.64(a).
 a permit to drill a well?
250.411  What material must   ?250.414(f)....  250.64(f).
 I submit with my
 application?
250.412  What requirements    ?250.414(f)(1).  250.64(f)(1).
 must my plat meet?
250.413  What items must my   250.414(f)(2)..  250.64(f)(2).
 description of well
 drilling design criteria
 address?

[[Page 38457]]

 
250.414  What items must my   250.414(f)(5)..  250.64(f)(5).
 drilling prognosis include?
250.415  What items must my   250.414(f)(4     250.64(f)(4 and 6).
 casing and cementing          and 6).
 programs include?
250.416  What information     250.414(f)(3)..  250.64(f)(3).
 must be included in the
 diverter and BOP
 descriptions?
250.417  What information     250.414(b).....  250.64(b).
 must I provide if I intend
 to use a mobile drilling
 unit to drill a proposed
 well?
250.418  What additional      250.414(f)(11).  250.64(f)(11).
 requirements must I meet?
250.420  What well casing     250.404(a)(1)..  250.54(a)(1)
 and cementing requirements   250.404(a)(2)..  250.54(a)(2).
 must I meet?
250.421  What are the casing  250.404(b),(c),  250.54(b),(c), (d), and
 and cementing requirements    (d), and (e).    (e).
 by type of casing string?
250.422  When may I resume    250.405(d).....  250.55(d).
 drilling after cementing?
250.423  How must I remedy    250.404 and      250.54 and .55.
 cementing and casing          .405.
 problems and situations?
250.424  What are the         250.405........  250.55.
 requirements for pressure
 testing casing?
250.425  What special         250.405........  250.55.
 pressure tests must I
 perform on casings for
 prolonged drilling
 operations?
250.426  What are the         250.405........  250.55.
 requirements for pressure
 testing liners?
250.427  What are the         250.405(a) and   250.55(a).
 recordkeeping requirements    New
 for casing and liner          requirement.
 pressure tests?
250.428  What are the         250.404(a)(6)..  250.54(a)(6).
 requirements for pressure
 integrity tests?
250.430  When must I install  250.409(a).....  250.59(a).
 a diverter system?
250.431  What are the         250.409(c).....  250.59(c).
 diverter design and
 installation requirements?
250.432  What must I do to    250.409(d).....  250.59(d).
 obtain a departure to
 diverter design and
 installation requirements?
250.433  How must I test the  250.409(f).....  250.59(f).
 diverter system after
 installation?
250.434  What are the         250.409(f).....  250.59(f).
 recordkeeping requirements
 for diverter tests?
250.440  What are the         250.406(a) and   250.56(a) and (b).
 general requirements for      (b).
 BOP systems and system
 components?
250.441  What are the         250.406(f).....  250.56(f).
 requirements for a surface
 BOP stack?
250.442  What are the         250.406(e).....  250.56(e).
 requirements for a subsea
 BOP stack?
250.443  What associated BOP  250.406(d).....  250.56(d).
 systems and related
 equipment must my BOP
 system include?
250.444  What are the choke   250.406(d)(7)..  250.56(d)(7).
 manifold requirements?
250.445  What are the         250.406(d)(10).  250.56(d)(10).
 requirements for kelly
 cocks, inside BOPs, and
 drill-string safety valves?
250.446  What must I do to    250.407(f) and   250.57(f) and (g).
 maintain and inspect my       (g).
 BOP?
250.447  When must I conduct  250.407(a).....  250.57(a).
 BOP system pressure tests?
250.448  What are the BOP     250.407(b) and   250.57(b) and (c).
 pressure tests                (c).
 requirements?
250.449  Are there            250.407(d).....  250.57(d).
 additional BOP testing
 requirements with which I
 must comply?
250.450  What are the         250.407(h).....  250.57(h).
 recordkeeping requirements
 for BOP tests?
250.451  How do I remedy BOP  250.407(c), (d)  250.57(c), (d) and (e).
 problems and situations?      and (e).
250.455  What are the         250.410(a).....  250.60(a).
 general requirements for a
 drilling fluid program?
250.456  What are the         250.410(b).....  250.60(b).
 required safe drilling
 fluid program practices?
250.457  What equipment must  250.410(c).....  250.60(c).
 I have to test and monitor
 drilling fluids?
250.458  What quantities of   250.410(d).....  250.60(d).
 drilling fluids are
 required?
250.459  What are the safety  250.410(e).....  250.60(e).
 requirements for drilling
 fluid-handling areas?
250.460  What are the         250.401(e)(1)    250.51(e)(1).
 requirements for well         and new
 testing?                      requirement
                               for well
                               testing.
250.461  What are the         250.401(e)(2),(  250.51(e)(2),(3), and
 requirements for              3), and (4).     (4).
 directional and inclination
 surveys?
250.462  What are the         250.408........  250.58.
 requirements for well-
 control drills?
250.463  Who establishes      250.412........  250.62.
 field drilling rules?
250.465  When must I submit   250.415........  250.65.
 forms to MMS?
250.466  What well records    250.416(a).....  250.66(a).
 must I keep?
250.467  What well records    250.416(c).....  250.66(c).
 may I be required to
 submit?
250.468  How long must I      250.416(a) and   250.66(a) and (g).
 keep drilling-related         (g).
 records?
250.469  Must I submit        250.416(d).....  250.66(d).
 copies of well logs?
250.470  Hydrogen sulfide     250.417........  250.67.
------------------------------------------------------------------------

Procedural Matters

Public Comments Procedures

    Our practice is to make comments, including names and home 
addresses of respondents, available for public review during regular 
business hours. Individual respondents may request that we withhold 
their home address from the rulemaking record, which we will honor to 
the extent allowable by law. There may be circumstances in which we 
would withhold from the rulemaking record a respondent's identity, as 
allowable by the law. If you wish us to withhold your name and/or 
address, you must state this prominently at the beginning of your 
comment. However, we will not consider anonymous comments. We will make 
all submissions from

[[Page 38458]]

organizations or businesses, and from individuals identifying 
themselves as representatives or officials of organizations or 
businesses, available for public inspection in their entirety.

Takings Implication Assessment (Executive Order (E.O.) 12630)

    According to E.O. 12630, the proposed rule does not have 
significant Takings Implications. A Takings Implication Assessment is 
not required. The proposed rule revises existing operation regulations. 
It does not prevent any lessee, operator, or drilling contractor from 
performing operations on the OCS, provided they follow the regulations. 
Thus, MMS did not need to prepare a Takings Implication Assessment 
pursuant to E.O. 12630, Governmental Actions and Interference with 
Constitutionally Protected Property Rights.

Regulatory Planning and Review (E.O. 12866)

    This proposed rule is a significant rule under E.O. 12866; 
therefore, OMB will review the proposed rule.
    (1) This proposed rule will not have an effect of $100 million or 
more on the economy. It will not adversely affect in a material way the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or State, local, or tribal governments or 
communities. The major purpose for this proposed rule is the 
restructuring of the rule and simplifying the regulatory language. The 
restructuring and plain language revisions will not result in any 
economic effects to small or large entities. Some of the proposed 
technical revisions will have a minor economic effect on lessees and 
drilling contractors. The cost of the rule is affected by the response 
of existing and future potential regulated entities to anticipated 
prices and returns in the energy markets. With increases in the prices 
of oil and natural gas, the amount of drilling activity and affected 
entities could increase as could the estimated cost of the proposed 
rule. However, even with such changes, MMS believes the rule will not 
have an annual effect on the economy of $100 million. Specifically, 
given the existing industry structure (i.e., the number and size of 
affected regulated entities remains constant), MMS estimates the first 
year cost to implement the rule at less than $15 million. Over 95 
percent of the estimated cost of the proposed rule is due to the 
acquisition and installation of the blind-shear rams. The recurring 
costs in the ensuing years, given no change to the existing structure 
of the OCS lessees and drilling contractors, are estimated at $1 
million annually.
    The majority of the cost to implement the proposed rule is due to 
the required installation of blind-shear rams ($14 million) in a 
surface BOP stack. The most significant benefits of preventing or 
minimizing some blowouts will be the reduced risk of injury or fatality 
to personnel and of environmental damage. Property damages (including 
lost productivity) resulting from blowouts will also be reduced by this 
proposed rule. Property and financial damages from a blowout or near 
blowout can range from minimal damage to a facility and the loss of a 
day's activity to the total loss of the drilling rig and production 
facility.
    MMS estimates that installation of a blind-shear ram in the BOP 
stack could prevent or minimize one blowout every 2 years. This 
estimate comes from the 12 incidents that MMS identified where a blind-
shear ram had helped or could have helped prevent or minimize a blowout 
over a 23+ year period (1977 to present). Considering that a single 
blowout could cause multiple injuries, fatalities, and tens of millions 
of dollars in property damage and financial losses, MMS believes that 
the benefits of this proposed requirement will more than offset the 
cost of this proposed requirement.
    (2) This proposed rule will not create a serious inconsistency or 
otherwise interfere with an action taken or planned by another agency. 
The proposed rule does not affect how lessees or operators interact 
with other agencies. Nor does this proposed rule affect how MMS will 
interact with other agencies.
    (3) This proposed rule does not alter the budgetary effects or 
entitlements, grants, user fees, or loan programs or the rights or 
obligations of their recipients. The proposed rule only addresses the 
regulatory requirements for obtaining permission to drill on the OCS 
and the safety of drilling operations.
    (4) This proposed rule does not raise novel legal or policy issues. 
The proposed rule involves some new policy issues, such as requiring 
minimum BOP maintenance requirements and blind-shear rams for surface 
BOP stacks, but these new policy decisions are not ``novel.'' They 
simply address recognized gaps in our safety regulations. These minimum 
requirements are generally accepted practices that are included in API 
documents.

Civil Justice Reform (E.O. 12988)

    According to E.O. 12988, the Office of the Solicitor has determined 
that this proposed rule does not unduly burden the judicial system and 
does meet the requirements of sections 3(a) and 3(b)(2) of the Order.

National Environmental Policy Act (NEPA)

    This proposed rule does not constitute a major Federal action 
significantly affecting the quality of the human environment. An 
environmental assessment is not required.

Paperwork Reduction Act (PRA) of 1995

    The proposed rule contains a collection of information that has 
been submitted to OMB for review and approval under Sec. 3507(d) of the 
PRA. As part of our continuing effort to reduce paperwork and 
respondent burdens, MMS invites the public and other Federal agencies 
to comment on any aspect of the reporting and recordkeeping burden. 
Submit your comments to the Office of Information and Regulatory 
Affairs; OMB; Attention: Desk Officer for the Department of the 
Interior (OMB control number 1010-NEW); 725 17th Street, NW, 
Washington, DC 20503. Send a copy of your comments to the Rules 
Processing Team, Attn: Comments; Mail Stop 4024; Minerals Management 
Service; 381 Elden Street; Herndon, Virginia 20170-4817. You may obtain 
a copy of the supporting statement for the new collection of 
information by contacting the Bureau's Information Collection Clearance 
Officer at (202) 208-7744.
    The PRA provides that an agency may not conduct or sponsor and a 
person is not required to respond to a collection of information unless 
it displays a currently valid OMB control number. OMB is required to 
make a decision concerning the collection of information contained in 
these proposed regulations between 30 to 60 days after publication of 
this document in the Federal Register. Therefore, a comment to OMB is 
best assured of having its full effect if OMB receives it by July 21, 
2000. This does not affect the deadline for the public to comment to 
MMS on the proposed regulations.
    The title of the collection of information for this proposed rule 
is ``Proposed Rulemaking--30 CFR 250, Subpart D--Oil and Gas Drilling 
Operations'' (OMB control number 1010-NEW). Respondents include 
approximately 130 Federal OCS oil and gas or sulphur lessees. The 
frequency of response is on occasion, daily, weekly, quarterly, or 
annually depending upon the requirement. Responses to this collection 
of information are mandatory. MMS will protect proprietary information 
according to the Freedom of

[[Page 38459]]

Information Act and 30 CFR 250.196, ``Data and information to be made 
available to the public.''
    The collection of information required by the current subpart D 
regulations is approved by OMB under control number 1010-0053. The 
proposed rule imposes very few changes to the information collection 
burden. The major changes are:
    <bullet> Notification of drilling rig movement on or off drilling 
location (+100 burden hours);
    <bullet> Incorporation of two new forms (Supplemental APD 
Information Sheet and Weekly Activity Report) separately approved under 
1010-0131 and 1010-0132; and
    <bullet> Submission of well testing plans (+30 burden hours).
    We estimate the total annual reporting and recordkeeping ``hour'' 
burden for the proposed rule to be 107,866 hours representing an 
average burden of 830 hours per respondent. Except for the items 
identified as ``new'' in the following chart, the burden estimates 
shown are those that are estimated for the current subpart D 
regulations. The public has had numerous opportunities to comment on 
the estimates during the process to renew the OMB approval of the 
information collection requirements in current regulations. We have 
also consulted with a representative sampling of respondents to verify 
these estimates.

                                                Burden Breakdown
----------------------------------------------------------------------------------------------------------------
                                     Reporting                                                           Annual
Citation 30 CFR 250 Subpart D       requirement         Frequency          Number           Burden       burden
----------------------------------------------------------------------------------------------------------------
402 [Current 411]............  Request approval to   On occasion....  6 requests.....  10 minutes.....         1
                                use blind or blind-
                                shear ram or pipe
                                rams and inside BOP.
403(c), 404 [New]............  Notify MMS of         On occasion....  1,000            6 minutes......       100
                                drilling rig                           notifications.
                                movement on or off
                                drilling location.
403(c) [Current 401].........  Request approval not  On occasion....  10 requests....  1 hour.........        10
                                to shut-in well
                                during equipment
                                movement.
410-418, plus various          APD to drill,           Burden covered under 1010-0044 (form MMS-123,           0
 references throughout          including various      APD); 1010-0131 (new collection form MMS-123S,
 subpart D*.                    approvals required          Supplemental APD Information Sheet).
                                in subpart D and
                                obtained via forms
                                MMS-123 and MMS-
                                123S, and
                                supporting
                                information. [*All
                                current
                                requirements in
                                various sections.].
410(c), 417(b) [Current 405].  Exploration Plan,        Burden covered under 1010-0049 (30 CFR 250,            0
                                Development and                          Subpart B)
                                Production Plan,
                                Development
                                Operations
                                Coordination
                                Document.
417(c) [Current 401].........  Submit 3rd party         Burden covered under 1010-0958 (30 CFR 250,            0
                                review of drilling                       Subpart I)
                                unit.
418(e) [Current 402].........  Submit welding and       Burden covered under 1010-0114 (30 CFR 250,            0
                                burning plan.                            Subpart A)
423 [Current 404/405]........  Submit revised        On occasion....  20% of 990       2 hours........       396
                                casing and                             drilling ops.
                                cementing program                      = 198.
                                or changes.
425 [Current 405]............  Caliper, pressure     Every 30 days    20% of 990       5 hours........       990
                                test, or evaluate     during pro       wells = 198.
                                casing; submit        longed
                                evaluation results;   drilling;
                                request approval
                                before resuming
                                operations or
                                beginning repairs.
456(c), (f) [Current 410]....  Perform various       On occasion,     144 drilling     .25 hour.......     1,872
                                calculations; post    daily, weekly.   rigs  x  52 =
                                information.                           7,488.
459(a)(3) [Current 410]......  Request exception to  On occasion....  5 requests.....  2 hours........        10
                                procedure for
                                protecting negative
                                pressure area.
460(b), (c) [New; Current      Submit plans for      On occasion....  15 plans.......  2 hours........        30
 401].                          well testing and
                                notify MMS before
                                test.
461(e) [Adjustment to current  Provide copy of well  On occasion....  10 occasions...  1 hour.........        10
 401].                          directional survey
                                to affected
                                leaseholder.
462(a) [Current 408].........  Prepare and post      On occasion....  26 plans.......  3 hours........        78
                                well control drill
                                plan for crew
                                members.
463(b) [Current 412].........  Request field         On occasion....  6 requests.....  2.7 hours......    \1\ 16
                                drilling rules be
                                established,
                                amended, or
                                canceled.
465, 467 [Current 415/416]...  Submit revised          Burden covered under 1010-0045 (form MMS-124,           0
                                plans, changes,       Sundry Notices and Reports); 1010-0046 (form MMS-
                                well/drilling                     125, Well Summary Report)
                                records, etc., on
                                forms MMS-124 or
                                MMS-125.
465(a), (b), (3); 467(c)       In the GOMR, submit     Burden included under 1010-0132 (new form MMS-          0
 [New].                         drilling activity               133) (Weekly Activity Report)
                                on form MMS-133 on
                                weekly basis.
465(a); 467 [Current 416]....  Submit well records,  On occasion,     20% of 990       3 hours........       594
                                daily drilling        daily.           wells = 198.
                                report and other
                                data as requested
                                or specified by
                                regional office.
469 [Current 416]............  Submit well logs and  On occasion....  990 wells......  1.5 hours......     1,485
                                survey results.
470(c)(4), (d) [Current 417].  Submit request for    On occasion....  27 responses...  1.7 hours......    \1\ 46
                                reclassification of
                                H<INF>2</INF>S zone; notify
                                MMS if conditions
                                change.
470(f) [Current 417].........  Submit contingency    On occasion....  27 plans (16     10 hours.......       270
                                plans for                              drill, 5
                                operations in H<INF>2</INF>S                      workover, 6
                                areas.                                 prod.).
470(i) [Current 417].........  Display warning        Not applicable: facilities would display warning         0
                                signs.                 signs and use other visual and audible systems
470(j)(12) [Current 417].....  Propose alternatives    Proposals would be submitted with contingency           0
                                to minimize or              plans; burden included in 250.470(f)
                                eliminate SO<INF>2</INF>
                                hazards.
470(j)(13)(vi) [Current 417].  Label breathing air   Not applicable: supplier normally labels bottles;         0
                                bottles.                   facilities would routinely label if not
470(l) [Current 417].........  Notify (phone) MMS    On occasion      49 facilities    .2 hour........    \1\ 20
                                of unplanned H<INF>2</INF>S      (apprx. 2/       x  2 = 98.
                                releases.             year).

[[Page 38460]]

 
470(o)(5) [Current 417]......  Request approval to   On occasion....  3 requests.....  2 hours........         6
                                use drill pipe for
                                well testing.
470(q)(1) [Current 417]......  Seal and mark for     Not applicable: facilities would mark transported         0
                                the presence of H<INF>2</INF>S                         cores
                                cores to be
                                transported.
470(q)(9) [Current 417]......  Request approval to   On occasion....  3 requests.....  2 hours........         6
                                use gas containing
                                H<INF>2</INF>S for instrument
                                gas.
470(q)(12) [Current 417].....  Analyze produced      On occasion      4 prod.          2.8 hours......   \1\ 582
                                water disposed of     (apprx.          platforms  x
                                for H<INF>2</INF>S content and   weekly).         52 = 208.
                                submit results to
                                MMS.
    Total Reporting:           ....................  ...............  10,516.........  ...............    6,522
----------------------------------------------------------------------------------------------------------------
\1\ Rounded.


----------------------------------------------------------------------------------------------------------------
                                   Recordkeeping                                                         Annual
Citation 30 CFR 250 Subpart D       requirement         Frequency          Number           Burden       burden
----------------------------------------------------------------------------------------------------------------
403 [Current 401]............  Perform operational   Weekly (52)....  144 drilling     .1 hour........   \1\ 749
                                check of crown                         rigs  x  52 =
                                block safety                           7,488.
                                device; record
                                results.
427 [Current 405]............  Perform pressure      On occasion....  144 drilling     2 hours........    14,400
                                test on all casing                     rigs  x
                                strings and                            apprx. 50 per
                                drilling liner lap;                    rig = 7,200.
                                record results.
428(a) [Current 404].........  Perform pressure-     On occasion....  425 tests......  4 hours........     1,700
                                integrity tests and
                                related hole-
                                behavior
                                observations;
                                record results.
434 [Current 409]............  Perform diverter      On occasion      990 drilling     2 hours........     3,960
                                tests when            (average 2 per   operations  x
                                installed and once    drilling op).    2 = 1,980.
                                every 7 days;
                                actuate system at
                                least once every 24-
                                hour period; record
                                results; retain
                                records 2 years
                                after drilling
                                completed.
450 [Current 407]............  Perform BOP pressure  When installed;  144 drilling     6 hours........    30,240
                                tests, actuations     at a minimum     rigs  x
                                and inspections;      every 14 days;   apprx. 35 per
                                record results;       as stated for    rig = 5,040.
                                retain records 2      components.
                                years following
                                completion of
                                drilling activity.
450 [Current 407]............  Function test         Every 7 days     144 drilling     .16 hour.......       461
                                annulars and rams;    between BOP      rigs  x  appx.
                                document results      tests            20 per rig =
                                (Note: this test is   (biweekly).      2,880.
                                part of BOP test
                                when BOP test is
                                conducted.).
451(c) [Current 407].........  Record reason for     On occasion      144 drilling     .1 hour........    \1\ 29
                                postponing BOP test.  (apprx. 2/       rigs  x  2 =
                                                      year).           288.
456(b); 457(a), 458(b)         Record each drilling  On occasion,     144 drilling     1.25 hours.....     9,360
 [Current 410].                 fluid circulation;    daily, weekly,   rigs  x  52 =
                                test drilling         quarterly.       7,488.
                                fluid, record
                                results; record
                                daily inventory of
                                drilling fluid/
                                materials; test and
                                recalibrate gas
                                detectors; record
                                results.
462(c) [Current 408].........  Perform well-control  On occasion (2   144 drilling     1 hour.........    14,688
                                drills; record        crews  x         rigs  x  102 =
                                results.              52=102).         14,688.
466, 468 [Current 416].......  Retain drilling       Annual records   990 wells......  1.5 hours......     1,485
                                records for 90 days   maintenance.
                                after drilling
                                complete; retain
                                casing/liner
                                pressure, diverter,
                                and BOP records for
                                2 years; retain
                                well completion/
                                well workover until
                                well is permanently
                                plugged/abandoned
                                or lease assigned.
470(g)(2), (g)(5) [Current     Conduct H<INF>2</INF>S           On occasion;     49 facilities    2 hours........       196
 417].                          training; post        annual           x  2 = 98.
                                safety                refresher
                                instructions;         (apprx. 2/
                                document training.    year).
470(h)(2) [Current 417]......  Conduct drills and    Weekly (52)....  49 facilities    1 hour.........     2,548
                                safety meetings;                       x  52 = 2,548.
                                document attendance.
470(j)(8) [Current 417]......  Test H<INF>2</INF>S detection    On occasion      26 drilling      2 hours........    18,980
                                and monitoring        (daily during    rigs  x  365
                                sensors during        drilling).       days = 9,490.
                                drilling; record
                                testing and
                                calibrations
                                (apprx. 12 sensors
                                per rig).
470(j)(8) [Current 417]......  Test H<INF>2</INF>S detection    14 days........  28 prod.         3.5 hours......     2,548
                                and monitoring                         platforms  x
                                sensors during                         26 weeks = 728.
                                production; record
                                testing and
                                calibrations
                                (apprx. 30 sensors
                                on 5 platforms +
                                apprx. 42 sensors
                                on 23 platforms).
    Total Recordkeeping:       ....................  ...............  ...............  ...............  101,344
----------------------------------------------------------------------------------------------------------------
\1\ Rounded.


[[Page 38461]]


Total Reporting..........................................   =      6,522
Total Recordkeeping......................................   =    101,344
                                                               ---------
Total Burden.............................................   =    107,866
 

    1. MMS specifically solicits comments on the following questions:
    (a) Is the proposed collection of information necessary for MMS to 
properly perform its functions, and will it be useful?
    (b) Are the estimates of the burden hours of the proposed 
collection reasonable?
    (c) Do you have any suggestions that would enhance the quality, 
clarity, or usefulness of the information to be collected?
    (d) Is there a way to minimize the information collection burden on 
those who are to respond, including the use of appropriate automated 
electronic, mechanical, or other forms of information technology?
    2. In addition, the PRA requires agencies to estimate the total 
annual reporting and recordkeeping ``non-hour cost'' burden resulting 
from the collection of information. We have not identified any, and we 
solicit your comments on this item. For reporting and recordkeeping 
only, your response should split the cost estimate into two components: 
(a) Total capital and start-up cost component and (b) annual operation, 
maintenance, and purchase of services component. Your estimates should 
consider the costs to generate, maintain, and disclose or provide the 
information. You should describe the methods you use to estimate major 
cost factors, including system and technology acquisition, expected 
useful life of capital equipment, discount rate(s), and the period over 
which you incur costs. Capital and start-up costs include, among other 
items, computers and software you purchase to prepare for collecting 
information; monitoring, sampling, drilling, and testing equipment; and 
record storage facilities. Generally, your estimates should not include 
equipment or services purchased: (1) Before October 1, 1995; (2) to 
comply with requirements not associated with the information 
collection; (3) for reasons other than to provide information or keep 
records for the Government; or (4) as part of customary and usual 
business or private practices.

Regulatory Flexibility (RF) Act

    The Department of the Interior (DOI) certifies that this proposed 
rule will not have a significant economic effect on a substantial 
number of small entities under the RF Act (5 U.S.C. 601 et seq.). This 
proposed rule applies to all lessees and drilling contractors that 
operate on the OCS. Small lessees and drilling contractors that operate 
under this proposed rule would fall under the Small Business 
Administration's (SBA) Standard Industrial Classification (SIC) codes 
1311 Crude Petroleum and Natural Gas and 1381 Drilling Oil and Gas 
Wells. Under these SIC codes, SBA considers all companies with fewer 
than 500 employees to be a small business. Given the variability in the 
industry to changes in the relative prices of oil and natural gas, the 
numbers of small entities affected by the proposed rule may change over 
time. Based on data from 1998, we estimate that of the 130 lessees that 
explore for and produce oil and gas on the OCS, approximately 90 are 
small businesses (70 percent). We also estimate that 20 drilling 
contractors operate on the OCS, and that only one of those drilling 
contractors is classified as a small business. The number of drilling 
contractors is based on current drilling activity on the OCS, and the 
size of each drilling contractor is based on research into company 
statistics.
    New compliance costs associated with this proposed rule fall within 
two categories--of meeting new drilling requirements and the cost of 
purchasing additional blind shear rams. Drilling requirement costs will 
be borne by the OCS lessees who explore for and produce oil and are 
dependent on the number of wells drilled. The cost of the blind shear 
rams will be borne by drilling contractors.
    We estimate that the total annual cost of the new drilling 
requirements proposed in this rule to be approximately $670,000, as 
shown in the following table. The table also shows the estimated cost 
per well for the approximately 700 wells drilled annually on the OCS 
using a surface BOP stack.

           Estimated Costs of Additional Drilling Requirements
------------------------------------------------------------------------
                                                          Total cost for
                                                             700 wells
                  Cost                     Cost per well      drilled
                                                             annually
------------------------------------------------------------------------
One hour per well additional evaluation             $100         $70,000
 time on cementing operations @ $100....
One hour per well additional drilling                850         595,000
 rig rental @ $850......................
Annual reporting and paperwork burden--               10           7,000
 140 hours @$50.........................
                                         -------------------------------
    Total...............................             960        672,000
------------------------------------------------------------------------
\*\ The annual reporting and paperwork burden for the entire Subpart D--
  ''Oil and Gas Drilling Operations' is 107,866 hours as indicated in
  the Paperwork Reduction Act of 1995 (PRA) section of this preamble.
  However, the new burden that would be added by this proposed rule is
  only 140 hours (Sec.  250.403(c)--100 hours; Sec.  250.460(b), (c)--30
  hours; and Sec.  250.461(e)--10 hours) as shown in the reporting and
  recordkeeping burden tables in the PRA section.

    As indicated in the table, the estimated cost per well is about 
$1,000. Based on drilling data from 1999, we estimate that the 90 small 
businesses that explore for and produce oil and gas on the OCS drill 
about 300 of the 700 wells drilled annually on the OCS using a surface 
BOP stack. Thus, with the small businesses drilling an average of 3\1/
3\ wells per year, the annual economic effect for each small business 
is about $3,300, or about $300,000 in total. The estimated additional 
cost of $1,000 per well is quite small (about .02 percent) when 
compared to the $5 million average cost of drilling a well. Based on 
this very low percentage of well cost, we believe that these proposed 
revisions to the regulations will not have a significant economic 
effect on any small lessee. However, we do invite comment on our 
analytical procedures, data inputs, and findings.
    The estimated economic effects of the requirement to use blind-
shear rams on surface BOP stacks is the cost to purchase the rams. This 
requirement imposes no reporting or recordkeeping burden. This 
requirement primarily will affect drilling contractors operating jackup 
and platform rigs on the OCS who will be required to purchase the rams. 
Using information from 1999, the cost for a set of 10,000 pounds per-
square-inch rams and associated equipment is about $175,000. Some sets 
of rams for lower-rated BOP stacks will cost less, while a few sets of 
rams will cost more for higher-rated BOP stacks,

[[Page 38462]]

but the average cost will remain at about $175,000.
    We estimate that drilling contractors will need to purchase a total 
of 80 blind shear rams to meet the proposed requirements. At an average 
cost of about $175,000, the economic impact will be $14,000,000. The 
largest drilling contractor may need to purchase up to 20 sets of 
blind-shear rams, while the one small drilling contractor will not need 
to purchase any blind-shear rams because the contractor already has 
blind-shear rams for its rigs. A large contractor may get a minor 
reduction in the cost with a bulk purchase, but this reduction should 
not significantly affect the competition between large and small 
contractors because the unit costs will not vary much. Purchase of the 
rams to meet the proposed requirements will be an initial one-time 
cost. A blind-shear ram should last for 20 years if properly 
maintained.
    The blind-shear ram requirement should not hinder the ability of 
lessees or contractors, including small businesses, to conduct business 
on the OCS. The proposed rule provides for a 1-year period after the 
effective date for drilling contractors to plan and purchase the rams 
and associated equipment. This will allow contractors sufficient time 
to obtain the equipment. In addition, several drilling contractors 
likely have one or more sets of blind-shear rams, because some lessees 
currently require the installation of these rams for their wells. Also, 
some contractors may choose not to outfit all of their rigs with blind-
shear rams immediately. Those contractors may continue to market those 
rigs in State or international waters where blind-shear rams are not 
required.
    The cost of blind-shear rams probably will affect the rates that 
drilling contractors charge lessees and operators to drill wells. 
Contractors base these rates, called day rates, primarily on the supply 
and demand of drilling rigs. We estimate that a minor increase in day 
rates (estimated at between $250 and $750 depending on rig capability 
and ram size) would increase the costs of drilling a typical OCS well 
by less than 1 percent. The minor increase in day rates to pay for the 
blind-shear rams should not last more than 3 years (the estimated time 
to pay for the rams). Since drilling contractors will have 1 year from 
the date of the final rule to purchase this equipment, they should have 
sufficient time to plan their purchase and adjust their day rates to 
reflect this cost. MMS believes the purchase of this equipment or any 
adjustments in day rates are unlikely to affect the competition between 
large and small drilling contractors.
    The following table summarizes the estimated economic effects 
associated with this proposed rule.

----------------------------------------------------------------------------------------------------------------
                                                                                                   Cost to small
                Requirement                               Frequency                 Total cost      businesses
----------------------------------------------------------------------------------------------------------------
New drilling rules.........................  Annual.............................        $672,000        $300,000
Use of blind shear rams....................  One-time...........................      14,000,000               0
                                                                                 -------------------------------
    Total..................................  ...................................      14,672,000         300,000
----------------------------------------------------------------------------------------------------------------

    As discussed above, we do not believe that this rule will have a 
significant impact on the lessees and drilling contractors who explore 
for and produce oil and gas on the OCS, including those that are 
classified as small businesses. MMS asks for comments on the expected 
duration of the anticipated costs and the finding that the impacts on 
small drilling contractors are not significant.
    Your comments are important. The Small Business and Agriculture 
Regulatory Enforcement Ombudsman and 10 Regional Fairness Boards were 
established to receive comments from small businesses about Federal 
agency enforcement actions. The Ombudsman will annually evaluate the 
enforcement activities and rate each agency's responsiveness to small 
business. If you wish to comment on the enforcement actions of MMS, 
call toll-free (888) 734-3247.

Small Business Regulatory Enforcement Fairness Act (SBREFA)

    This proposed rule is not a major rule under (5 U.S.C. 804(2)) the 
SBREFA. This proposed rule:
    (a) Does not have an annual effect on the economy of $100 million 
or more. As described above, we estimate that the initial one-time cost 
of the proposed rule to be $14 million and $672,000 in subsequent 
years. These costs will not cause an annual effect on the economy of 
$100 million.
    (b) Will not cause a major increase in costs or prices or 
consumers, individual industries, Federal, State, or local government 
agencies, or geographic regions. The minor increase in drilling costs 
will not change the way the oil and gas industry conducts business, nor 
will it affect regional oil and gas prices; therefore, it will not 
cause major cost increases for consumers, the oil and gas industry, or 
any Government agencies.
    (c) Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or ability of U.S.-
based enterprises to compete with foreign-based enterprises. All 
lessees and drilling contractors, regardless of nationality, will have 
to comply with the requirements of this rule. So the rule will not 
affect competition, employment, investment, productivity, innovation, 
or the ability of U.S.-based enterprises to compete with foreign-based 
enterprises.

Unfunded Mandates Reform Act (UMRA) of 1995 (E.O. 12866)

    This proposed rule does not impose an unfunded mandate on State, 
local, or tribal governments or the private sector of more than $100 
million per year. The proposed rule does not have any Federal mandates 
nor does the proposed rule have a significant or unique effect on 
State, local, or tribal governments or the private sector. A statement 
containing the information required by the UMRA (2 U.S.C. 1531 et seq.) 
is not required.

Federalism (E.O. 13132)

    According to E.O. 13132, this rule does not have Federalism 
implications. This proposed rule does not substantially and directly 
affect the relationship between the Federal and State Governments. The 
rule applies to lessees and drilling contractors that operate on the 
OCS. This rule does not impose costs on States or localities. Any costs 
will be the responsibility of the lessees and drilling contractors.

Clarity of This Regulation

    E.O. 12866 requires each agency to write regulations that are easy 
to understand. We invite your comments on how to make this proposed 
rule easier to understand, including answers to questions such as the 
following:
    (1) Are the requirements in the proposed rule clearly stated?
    (2) Does the proposed rule contain technical language or jargon 
that interfere with its clarity?

[[Page 38463]]

    (3) Does the format of the proposed rule (grouping and order of 
sections, use of headings, paragraphing, etc.) aid or reduce its 
clarity?
    (4) Would the proposed rule be easier to understand if it were 
divided into more (but shorter) sections?
    (5) Is the description of the proposed rule in the ``Supplementary 
Information'' section of this preamble helpful in understanding the 
proposed rule? What else can we do to make the proposed rule easier to 
understand?
    Send a copy of any comments that concern how we could make this 
proposed rule easier to understand to: Office of Regulatory Affairs, 
Department of the Interior, Room 7229, 1849 C Street, NW, Washington, 
DC 20240. You may also e-mail the comments to this address: 
<a href="/cdn-cgi/l/email-protection#094c717a6c6a4960667a276d6660276e667f"><span class="__cf_email__" data-cfemail="44013c372127042d2b376a202b2d6a232b32">[email protected]</span></a>

List of Subjects in 30 CFR Part 250

    Continental shelf, Environmental impact statements, Environmental 
protection, Government contracts, Incorporation by reference, 
Investigations, Mineral royalties, Oil and gas development and 
production, Oil and gas exploration, Oil and gas reserves, Penalties, 
Pipelines, Public lands--mineral resources, Public lands--rights-of-
way, Reporting and recordkeeping requirements, Sulphur development and 
production, Sulphur exploration, Surety bonds.

    Dated: February 11, 2000.
Sylvia V. Baca,
Acting Assistant Secretary, Land and Minerals Management.

    For the reasons stated in the preamble, the MMS proposes to amend 
30 CFR Part 250 as follows:

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

    1. The authority citation for part 250 continues to read as 
follows:

    Authority: 43 U.S.C. 1331 et seq.

    2. In Sec. 250.198, in the table in paragraph (e), the following 
changes are made in alphanumeric order:
    A. Add an entry for API RP 53 as set forth below.
    B. Revise the entry for API RP 500 as set forth below.


Sec. 250.198  Documents incorporated by reference.

* * * * *
    (e) * * *

------------------------------------------------------------------------
                                               Incorporated by reference
              Title of documents                           at
------------------------------------------------------------------------
 
  *                *                *                *                *
                                 *                *
API RP 53, Recommended Practice for Blowout    Sec.  250.442(b); Sec.
 Prevention Equipment Systems for Drilling      250.446(a).
 Wells, Third Edition, March 1997, API Stock
 No. G53003
API RP 500, Recommended Practice for            Sec.  250.459; Sec.
 Classification of Locations for Electrical     250.802(e)(4)(I); Sec.
 Installations at Petroleum Facilities, First   250.803(b)(9)(I); Sec.
 Edition, June 1, 1991, API Stock No. G06005    250.1628(b)(3);
                                                (d)(4)(I); Sec.
                                                250.1629(b)(4)(I).
 
  *                *                *                *                *
                                 *                *
------------------------------------------------------------------------

    3. In 30 CFR part 250, subpart D, Sec. 250.417 is redesignated as 
Sec. 250.470, Secs. 250.400 through 250.416 are revised, and 
Secs. 250.417 through 250.469 are added and a new undesignated center 
heading is added preceding redesignated Secs. 250.470 to read as set 
forth below. For the convenience of the reader, the table of contents 
for subpart D is also set forth below:
Subpart D--Oil and Gas Drilling Operations
Sec.
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 safety requirements must my drilling unit meet?
250.404  What mobile drilling unit movements must I report?

Application for Permit To Drill Requirements

250.410  How can I apply for a permit to drill a well?
250.411  What material must I submit with my application?
250.412  What requirements must my plat meet?
250.413  What items must my description of well drilling design 
criteria address?
250.414  What items must my drilling prognosis include?
250.415  What items must my casing and cementing programs include?
250.416  What information must be included in the diverter and BOP 
descriptions?
250.417  What information must I provide if I intend to use a mobile 
drilling unit to drill a proposed rule?
250.418  What additional requirements must I meet?

Casing and Cementing Requirements

250.420  What well casing and cementing requirements must I meet?
250.421  What are the casing and cementing requirements by type of 
casing string?
250.422  When may I resume drilling after cementing?
250.423  How must I remedy cementing and casing problems and 
situations?
250.424  What are the requirements for pressure testing casing?
250.425  What special pressure tests must I perform on casings for 
prolonged drilling operations?
250.426  What are the requirements for pressure testing liners?
250.427  What are the recordkeeping requirements for casing and 
liner pressure tests?
250.428  What are the requirements for pressure integrity tests?

Diverter System Requirements

250.430  When must I install a diverter system?
250.431  What are the diverter design and installation requirements?
250.432  What must I do to obtain a departure to diverter design and 
installation requirements?
250.433  How must I test the diverter system after installation?
250.434  What are the recordkeeping requirements for diverter tests?

Blowout Preventer (BOP) System Requirements

250.440  What are the general requirements for BOP systems and 
system components?
250.441  What are the requirements for a surface BOP stack?
250.442  What are the requirements for a subsea BOP stack?
250.443  What associated BOP systems and related equipment must my 
BOP system include?
250.444  What are the choke manifold requirements?
250.445  What are the requirements for kelly cocks, inside BOPs, and 
drill-string safety valves?
250.446  What must I do to maintain and inspect my BOP?
250.447  When must I conduct BOP system pressure tests?
250.448  What are the BOP pressure tests requirements?
250.449  What additional BOP testing requirements must I comply 
with?
250.450  What are the recordkeeping requirements for BOP tests?

[[Page 38464]]

250.451  How do I remedy BOP problems and situations?

Drilling Fluid Requirements

250.455  What are the general requirements for a drilling fluid 
program?
250.456  What are the required safe drilling fluid program 
practices?
250.457  What equipment must I have to test and monitor drilling 
fluids?
250.458  What quantities of drilling fluids are required?
250.459  What are the safety requirements for drilling fluid-
handling areas?

Other Drilling Requirements

250.460  What are the requirements for well testing?
250.461  What are the requirements for directional and inclination 
surveys?
250.462  What are the requirements for well-control drills?
250.463  Who establishes field drilling rules?

Sundry Notices and Well Records

250.465  When must I submit sundry notices to MMS?
250.466  What well records must I keep?
250.467  What well records may I be required to submit?
250.468  How long must I keep drilling-related records?
250.469  Must I submit copies of well logs?

Hydrogen Sulfide

250.470  Hydrogen sulfide.

Subpart D--Oil and Gas Drilling Operations

General Requirements


Sec. 250.400  Who is subject to the requirements of this subpart?

    The requirements of this subpart apply to lessees, operators, and 
their contractors and subcontractors.


Sec. 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 that represents your interests and can 
fulfill your responsibilities;
    (c) Ensure that the toolpusher or a member of the drilling crew 
maintains continuous surveillance of the rig floor from the beginning 
of drilling operations until the well is abandoned, unless you have 
secured the well with blowout preventers (BOPs) or packers;
    (d) Use personnel trained according to the provisions of subpart O; 
and
    (e) Use and maintain equipment and materials necessary to ensure 
the safety and protection of personnel, equipment, natural resources, 
and the environment.


Sec. 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 as deep as possible within a properly 
cemented casing string.
    (a) Among the events that may cause you to interrupt drilling 
operations are:
    (1) Evacuation of the drilling crew;
    (2) Inability to keep the drilling rig on location, or
    (3) Repair to major drilling or well-control equipment;
    (b) For floating drilling operations, the District Supervisor may 
approve the use of a blind or blind-shear ram or pipe rams and an 
inside BOP if you don't have time to install a downhole safety device 
or if special circumstances occur.


Sec. 250.403  What safety requirements must my drilling unit meet?

    Your drilling unit must meet all of the safety requirements in this 
section.

------------------------------------------------------------------------
                                                         Additional
    Required safety measure       When required         requirements
------------------------------------------------------------------------
(a) Crown block safety device.  For each drilling  (1) The device must
                                 unit.              prevent the
                                                    traveling block from
                                                    striking the crown
                                                    block.
                                                   (2) You must check
                                                    the device for
                                                    proper operation
                                                    once a week and
                                                    after each drill-
                                                    line slipping
                                                    operation.
                                                   (3) You must record
                                                    the results of this
                                                    operational check in
                                                    the driller's
                                                    report.
(b) Diesel engine air intake    For each diesel    (1) For a diesel
 shutdown device.                engine\1\..        engine that is not
                                                    continuously manned,
                                                    you must install an
                                                    automatic shutdown
                                                    device.\1\
                                                   (2) For a diesel
                                                    engine that is
                                                    continuously manned,
                                                    you may install
                                                    either a manual or
                                                    automatic air intake
                                                    shutdown device.
(c) Shut in all producible      When you move a    You must shut in each
 wells located in the affected   drilling rig or    well below the
 wellbay.                        related            surface and at the
                                 equipment on a     wellhead, unless
                                 platform.          otherwise approved
                                                    by the District
                                                    Supervisor.
(d) Emergency shutdown station  When you conduct
 installed near the driller's    drilling
 console.                        operations on a
                                 platform that
                                 has producing
                                 wells or other
                                 hydrocarbon flow
                                 .
------------------------------------------------------------------------
\1\ You do not need to install an air-intake shutdown device on a diesel
  engine that starts a larger engine or that powers any of the
  following: (1) Firewater pumps; (2) Emergency generators; (3) BOP
  accumulator systems; (4) Air supply to divers or confined entry
  personnel; (5) Temporary equipment on nonproducing platforms; or (6)
  Portable single cylinder rig washers.

Sec. 250.404  What mobile drilling unit movements must I report?

    You must report the movement of a mobile drilling unit on and off a 
drilling location to the District Supervisor. You must inform the 
District Supervisor 24 hours before the arrival of the rig on location 
and 24 hours before the rig departs from the location.

Applying for a Permit to Drill


Sec. 250.410  How can I apply for a permit to drill a well?

    (a) You must obtain written or oral approval from the District 
Supervisor before you begin drilling any well. To obtain approval, you 
must :
    (1) Submit the forms required by paragraph (b) of this section;
    (2) Submit the information required by Sec. 250.411;
    (3) Include the well in your approved Exploration Plan (EP), 
Development and Production Plan (DPP), or Development Operations 
Coordination Document (DOCD); and
    (4) Meet the oil spill financial responsibility requirements for 
offshore facilities as required by 30 CFR part 253.
    (b) You must submit the following forms to the District Supervisor:
    (1) An original and two copies of form MMS-123, Application for a 
Permit to Drill (APD);
    (2) A separate public information copy of form MMS-123 that meets 
the requirements of Sec. 250.127; and

[[Page 38465]]

    (3) Form MMS-123S, APD Information Sheet.


Sec. 250.411  What material must I submit with my application?

    In addition to forms MMS-123 and MMS-123S, you must include the 
information described in the following table.

------------------------------------------------------------------------
                                                           Where to find
      Information that you must include with an APD        a description
------------------------------------------------------------------------
(a) Plat that shows locations of the proposed well......   Sec.  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 a mobile drilling unit.......         250.417
(g) Additional requirements.............................         250.418
------------------------------------------------------------------------

Sec. 250.412  What requirements must my plat meet?

    (a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
    (b) Show the surface and subsurface locations of the proposed well 
and all the wells in the vicinity;
    (c) Show the surface and subsurface locations of the proposed well 
in feet or meters from the block line;
    (d) Contain the longitude and latitude coordinates, and either 
Universal Transverse Mercator grid-system coordinates or state plane 
coordinates in the Lambert or Transverse Mercator Projection system for 
the surface and subsurface locations of the proposed well; and
    (e) State the units and geodetic datum (including whether the datum 
is North American Datum 27 or 83) for these coordinates. If the datum 
was converted, you must state the method used for this conversion, 
since the various methods may produce different values.


Sec. 250.413  What items must my description of well drilling design 
criteria address?

    (a) Pore pressures;
    (b) Formation fracture gradients, adjusted for water depth;
    (c) Potential lost circulation zones;
    (d) Drilling fluid weights;
    (e) Casing setting depths;
    (f) Maximum anticipated surface pressures. For this section, 
maximum anticipated surface pressures are the pressures that you 
reasonably expect to be exerted upon a casing string and its related 
wellhead equipment. In calculating maximum anticipated surface 
pressures, you must consider: drilling, completion, and producing 
conditions; drilling fluid densities to be used below various casing 
strings; fracture gradients of the exposed formations; casing setting 
depths; total well depth; formation fluid types; safety margins; and 
other pertinent conditions. You must include the calculations used to 
determine the pressures for the drilling and the completion phases, 
including the anticipated surface pressure used for designing the 
production string;
    (g) A single plot containing estimated pore pressures, formation 
fracture gradients, proposed drilling fluid weights, and casing setting 
depths in true vertical measurements;
    (h) A summary report of the shallow hazards site survey that 
describes the geological and manmade conditions; and
    (i) Permafrost zones, if applicable.


Sec. 250.414  What items must my drilling prognosis include?

    (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 Sec. 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 faults; and
    (g) Estimated depths of permafrost, if applicable.


Sec. 250.415  What items must my casing and cementing programs include?

    (a) Hole sizes and casing sizes, including: weights; grades; 
tension, collapse, and burst values; types of connection; and setting 
depths (measured and true vertical depth);
    (b) Casing design safety factors for tension, collapse, and burst 
with the assumptions made to arrive at these values;
    (c) Type and amount of cement (in cubic feet) planned for each 
casing string; and
    (d) In areas containing permafrost, setting depths for conductor 
and surface casing based on the anticipated depth of the permafrost. 
Your program must provide protection from thaw subsidence and 
freezeback effect, proper anchorage, and well control.


Sec. 250.416  What information must be included 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 preventer 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; and
    (d) A schematic drawing of the BOP system that shows the inside 
diameter of the BOP stack, number and type of preventers, location of 
choke and kill lines, and associated valves.


Sec. 250.417  What information must I provide if I intend to use a 
mobile drilling unit to drill a proposed well?

    (a) Fitness requirements. You must provide information and data to 
demonstrate the drilling unit's capability to perform at the proposed 
drilling operation. This information must include the maximum 
environmental and operational conditions that the unit is designed to 
withstand, including the minimum air gap necessary for both hurricane 
and non-hurricane seasons. If sufficient environmental information and 
data are not available, the District Supervisor may require you to 
collect and report this information.
    (b) Foundation requirements. You must provide information to show 
that site-specific soil and oceanographic conditions are capable of 
supporting the proposed drilling unit. If you provided sufficient site-
specific information in your EP, DPP, or DOCD, you may reference that 
information. The District Supervisor may require you to conduct

[[Page 38466]]

additional surveys and soil borings before approving the APD.
    (c) Third-party review. If the design of the drilling unit is 
unique or has not been proven for use in the proposed environment, the 
District Supervisor may require you to submit a third-party review of 
the unit's design. If required, you must obtain the third-party review 
according to Sec. 250.903. You may submit this information before 
submitting an APD.
    (d) Frontier areas. If you plan to drill in a frontier area, you 
must have a contingency plan that addresses design and operating 
limitations of the drilling unit. Your plan must identify the actions 
necessary to maintain safety and prevent damage to the environment. 
Actions must include the suspension, curtailment, or modification of 
drilling or rig operations to remedy various operational or 
environmental situations (e.g. vessel motion, riser offset, anchor 
tensions, wind speed, wave height, currents, icing or ice-loading, 
settling, tilt or lateral movement, resupply capability).
    (e) U.S. Coast Guard (USCG) Documentation. You must provide the 
current Certificate of Inspection or Letter of Compliance from the 
USCG. You must also provide current documentation of any operational 
limitations imposed by an appropriate classification society.
    (f) Floating drilling unit. If you use a floating drilling unit, 
you must have a contingency plan for moving off location in an 
emergency situation.
    (g) Inspection of unit. The drilling unit must be available for 
inspection by the District Supervisor before commencing operations.
    (h) Once the District Supervisor has approved a mobile drilling 
unit for use, you do not need to re-submit the information required by 
this section unless changes in equipment affect its rated capacity to 
operate in the District.


Sec. 250.418  What additional requirements must I meet?

    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) 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) Proposed directional plot if the well is to be directionally 
drilled;
    (d) Hydrogen Sulfide Contingency Plan (refer to Sec. 250.470) if 
applicable and not previously submitted;
    (e) Welding and Burning Plan (refer to Sec. 250.106) if applicable 
and not submitted previously;
    (f) In areas subject to subfreezing conditions, evidence that the 
drilling equipment, BOP systems and components, diverter systems, and 
other associated equipment and materials are suitable for operating 
under such conditions;
    (g) A list and description of all requests for using alternative 
procedures or departures from the requirements of this subpart in one 
place in the APD. You must explain how the alternative procedures 
afford an equal or greater degree of protection, safety, or 
performance, or why you need the departure; and
    (h) Such other information as the District Supervisor may require.

Casing and Cementing Requirements


Sec. 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 
Secs. 250.421 through 250.428.
    (a) What casing and cementing programs must do. Your casing and 
cementing programs must:
    (1) Properly control formation pressures and fluids;
    (2) Prevent the direct or indirect release of fluids from any 
stratum through the wellbore into offshore waters;
    (3) Prevent communication between separate hydrocarbon-bearing 
strata;
    (4) Protect freshwater aquifers from contamination; and
    (5) Support unconsolidated sediments.
    (b) Casing requirements. (1) You must design casing (including 
liners) to withstand the anticipated stresses imposed by tensile, 
compressive, and buckling loads; burst and collapse pressures; thermal 
effects; and combinations thereof.
    (2) The casing design must include safety measures that ensure well 
control during drilling and safe operations during the life of the 
well.
    (c) Cementing requirements. You must design and conduct your 
cementing jobs so that cement composition, placement techniques, and 
waiting times ensure that the cement placed behind the bottom 500 feet 
of casing attains a minimum compressive strength of 500 psi.


Sec. 250.421  What are the casing and cementing requirements by type of 
casing string?

    The table in this section identifies specific design, setting, and 
cementing requirements for casing strings and liners. For the purposes 
of subpart D, the casing strings in order of normal installation are as 
follows: drive or structural, conductor, surface, intermediate, and 
production casings (including liners). The District Supervisor 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   If you drilled a portion of this
                                      to the minimum depth as approved or    hole, you must use enough cement to
                                      prescribed by the District             fill the annular space back to the
                                      Supervisor.                            mudline.
(b) Conductor......................  Design casing and select setting       Use enough cement to fill the
                                      depths based on relevant engineering   calculated annular space back to
                                      and geologic factors. These factors    the mudline.
                                      include the presence or absence of    Verify annular fill by observing
                                      hydrocarbons, potential hazards, and   cement returns. If you cannot
                                      water depths.                          observe cement returns, use
                                     Set casing immediately before           additional cement to ensure fill-
                                      drilling into formations known to      back to the mudline.
                                      contain oil or gas. If you encounter  For drilling on an artificial island
                                      oil or gas or unexpected formation     or when using a glory hole, you
                                      pressure before the planned casing     must discuss the cement fill level
                                      point, you must set casing             with the District Supervisor.
                                      immediately.
(c) Surface........................  Design casing and select setting       Use enough cement to fill the
                                      depths based on relevant engineering   calculated annular space to at
                                      and geologic factors. These factors    least 200 feet inside the conductor
                                      include the presence or absence of     casing.
                                      hydrocarbons, potential hazards, and  When geologic conditions such as
                                      water depths.                          near-surface fractures and faulting
                                                                             exist, you must use enough cement
                                                                             to fill the calculated annular
                                                                             space to the mudline.

[[Page 38467]]

 
(d) Intermediate...................  Design casing and select setting       Use enough cement to cover and
                                      depth based on anticipated or          isolate all hydrocarbon-bearing
                                      encountered geologic characteristics   zones in the well.
                                      or wellbore conditions.               As a minimum, you must cement the
                                                                             annular space 500 feet above the
                                                                             casing shoe and each zone to be
                                                                             isolated.
(e) Production.....................  Design casing and select setting       Use enough cement to cover or
                                      depth based on anticipated or          isolate all hydrocarbon-bearing
                                      encountered geologic characteristics   zones above the shoe. As a minimum,
                                      or wellbore conditions.                you must cement the annular space
                                                                             at least 500 feet above the casing
                                                                             shoe and the uppermost hydrocarbon-
                                                                             bearing zone.
(f) Liners.........................  If you use a liner as conductor or     Same as cementing requirements for
                                      surface casing, you must set the top   specific casing types. For example,
                                      of the liner at least 200 feet above   a liner used as intermediate casing
                                      the previous casing/liner shoe.        must be cemented according to the
                                     If you use a liner as an intermediate   cementing requirements for
                                      or production casing, you must set     intermediate casing.
                                      the top of the liner at least 100
                                      feet above the previous casing shoe.
----------------------------------------------------------------------------------------------------------------

Sec. 250.422  When may I resume drilling after cementing?

    (a) After cementing surface, intermediate, or production casing (or 
liners), you may not resume drilling until the cement has been held 
under pressure for 12 hours. For conductor casing, you may not resume 
drilling until the cement has been held under pressure for 8 hours. 
Methods of holding cement under pressure include using float valves to 
hold the cement in place.
    (b) If you plan to nipple down your diverter or BOP stack during 
the 8- or 12-hour waiting time, you must determine, in advance, when it 
will be safe to conduct this activity. Your determination must consider 
cement composition, well conditions, and the effects of nippling down 
the equipment.


Sec. 250.423  How must I remedy cementing and casing problems and 
situations?

    The table in this section describes remedies to problems and 
situations that lessees encounter on a regular basis during casing and 
cementing activities.

------------------------------------------------------------------------
  If you have the following
    problem or situation:                 Then you must . . .
------------------------------------------------------------------------
(a) Encounter unexpected       Submit a revised casing program to the
 formation pressures or         District Supervisor for approval.
 conditions that warrant
 revising your casing design.
(b) Change casing setting      Submit those changes to the District
 depths more than 100 feet      Supervisor for approval.
 from the approved APD.
(c) Indication of inadequate   (1) Pressure test the casing shoe,
 cement job (such as lost      (2) Run a temperature survey,
 returns, cement channeling,   (3) Run a cement bond log, or
 or failure of equipment).     (4) Use a combination of these
                                techniques.
(d) Inadequate cement job....  Re-cement or take other remedial actions
                                as approved by the District Supervisor.
(e) Primary cement job did     Isolate those intervals from normal
 not isolate abnormal           pressures by squeeze cementing before
 pressure intervals.            you complete; suspend operations; or
                                abandon the well, whichever occurs
                                first.
(f) Plan to produce a well...  Have at least two cemented casing strings
                                (does not include liners) in the well.
(g) Plan to wash out or        Obtain approval from the District
 displace some cement to        Supervisor.
 facilitate casing removal
 upon well abandonment.
(h) Plan to drill a well       Submit geologic data and information to
 without setting conductor      the District Supervisor that
 casing.                        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.
(i) Plan to use less than      Submit information to the District
 required cement for the        Supervisor that demonstrates the use of
 surface casing during          less cement is necessary to provide
 floating drilling operations.  protection from burst and collapse
                                pressures.
(j) Plan to cement across a    Use cement that sets before it freezes
 permafrost zone.               and has a low heat of hydration.
(k) Plan to leave the annulus  Fill the annulus with a liquid that has a
 opposite a permafrost zone     freezing point below the minimum
 uncemented.                    permafrost temperature and minimizes
                                corrosion.
(l) If your problem or         Contact the District Supervisor.
 situation is not described
 in this table.
------------------------------------------------------------------------

Sec. 250.424  What are the requirements for pressure testing casing?

    (a) You must pressure test each string of casing to 70 percent of 
its minimum internal yield. This testing requirement does not apply to 
drive or structural casing. When a diverter is installed on conductor 
casing, you must test the casing to a minimum of 200 psi. The District 
Supervisor may approve or require other casing test pressures.
    (b) You may not resume drilling or other down-hole operations until 
you obtain a satisfactory pressure test. If the pressure declines more 
than 10 percent in a 30-minute test or if there is another indication 
of a leak, you must re-cement, repair the casing, or run additional 
casing to provide a proper seal.


Sec. 250.425  What special pressure tests must I perform on casings for 
prolonged drilling operations?

    (a) If wellbore operations continue for more than 30 days within a 
casing string run to the surface, you must stop drilling operations as 
soon as

[[Page 38468]]

practicable thereafter and evaluate the effects of the prolonged 
operations on continued drilling operations and the life of the well. 
At a minimum, you must:
    (1) Caliper or pressure test the casing; and
    (2) Report the results of your evaluation to the District 
Supervisor and obtain approval of those results before resuming 
operations.
    (b) If casing integrity has deteriorated to a level below minimum 
safety factors, you must:
    (1) Repair the casing or run another casing string; and
    (2) Obtain approval from the District Supervisor before you begin 
repairs.


Sec. 250.426  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 Supervisor may 
approve or require other liner test pressures.
    (b) You must test each production liner (and liner-lap) to a 
minimum of 500 psi above the formation fracture pressure at the casing 
shoe into which the liner is lapped.
    (c) You may not resume drilling or other down-hole operations until 
you obtain a satisfactory pressure test. If the pressure declines more 
than 10 percent in a 30-minute test or if there is another indication 
of a leak, you must re-cement, repair the liner, or run additional 
casing/liner to provide a proper seal.


Sec. 250.427  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. In addition, you must record each test on a 
pressure chart and have your onsite representative certify (sign and 
date) the test as correct.


Sec. 250.428  What are the requirements for pressure integrity tests?

    You must conduct a pressure integrity test below the surface 
casing/liner and intermediate casing(s)/liner(s). The District 
Supervisor may require you to run a pressure-integrity test at the 
conductor casing shoe if warranted by local geologic conditions or the 
planned casing setting depth. You must conduct each pressure integrity 
test after drilling no more than 50 feet of new hole below the casing 
shoe. You must test to either the formation leak-off pressure or to an 
equivalent drilling fluid weight if identified in an approved APD.
    (a) You must use the pressure integrity test and related hole-
behavior observations, such as pore-pressure test results, gas-cut 
drilling fluid, and well kicks to adjust the drilling fluid program and 
the setting depth of the next casing string. You must record all test 
results and hole-behavior observations made during the course of 
drilling related to formation integrity and pore pressure in the 
driller's report.
    (b) While drilling, you must maintain the safe drilling margin 
identified in the approved APD. When you cannot maintain this safe 
margin, you must suspend drilling operations and remedy the situation.

Diverter System Requirements


Sec. 250.430  When must I install a diverter system?

    You must install a diverter system before you drill a conductor or 
surface hole. 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. The 
diverter system consists of a diverter sealing element, diverter lines, 
and control systems.


Sec. 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 an 
internal diameter of at least 10 inches for surface wellhead 
configurations and at least 12 inches for floating drilling operations;
    (b) Use dual diverter lines arranged to provide for downwind 
diversion capability;
    (c) Use at least two diverter control stations. One station must be 
on the drilling floor. The other 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 damage 
by thrown or falling objects.


Sec. 250.432  What must I do to obtain a departure to diverter design 
and installation requirements?

    The table below describes possible departures to the diverter 
requirements and the conditions required for each departure. To obtain 
one of these departures, you must have discussed or noted the departure 
in your APD.

------------------------------------------------------------------------
      If you want a departure to:              Then you must . . .
------------------------------------------------------------------------
(a) Use flexible hose for diverter       Use flexible hose that has
 lines instead of rigid pipe.             integral end couplings.
(b) Use only one spool outlet for your   (1) Have branch lines that meet
 diverter system.                         the minimum internal diameter
                                          requirements: and
                                         (2) provide downwind diversion
                                          capability.
(c) Use a spool with an outlet with an   Use a spool that has dual
 internal diameter of less than 10        outlets with an internal
 inches on a surface wellhead.            diameter of at least 8 inches.
(d) Use a single diverter line for       Maintain an appropriate vessel
 floating drilling operations on a        heading to provide for
 dynamically positioned drillship.        downwind diversion.
(e) If the departure you need is not     Contact the District
 described in this table.                 Supervisor.
------------------------------------------------------------------------

Sec. 250.433  How must I test the diverter system after installation?

    When you install the diverter system, you must actuate the diverter 
sealing element, diverter valves, and diverter-control systems and 
control stations. You must also flow-test the vent lines.
    (a) For drilling operations with a surface wellhead configuration, 
you must actuate the diverter system at least once every 24-hour period 
after the initial test. After you have nippled up on conductor casing, 
you must pressure-test the diverter-sealing element and diverter valves 
to a minimum of 200 psi. While the diverter is installed, you must

[[Page 38469]]

conduct subsequent pressure tests within 7 days of the previous test.
    (b) For floating drilling operations with a subsea BOP stack, you 
must actuate the diverter system at least once every 7 days after the 
previous test.
    (c) You must alternate actuations and tests between control 
stations.


Sec. 250.434  What are the recordkeeping requirements for diverter 
tests?

    You must record the time, date, and results of all diverter 
actuations and tests in the driller's report. In addition, you must:
    (a) Record the diverter pressure test on a pressure chart;
    (b) Require your onsite representative to certify (sign and date) 
the pressure test chart as correct;
    (c) Identify the control station or pod 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;
    (e) Retain all pressure charts and reports pertaining to the 
diverter tests and actuations at the facility for the duration of 
drilling; and
    (f) After drilling is completed, retain all the records listed in 
this section for 2 years at the facility, at the lessee's field office 
nearest to the facility, or at another location conveniently available 
to the District Supervisor.

Blowout Preventer (BOP) System Requirements


Sec. 250.440  What are the general requirements for BOP systems and 
system components?

    You must design, install, maintain, and use the BOP system and 
system components to ensure well control. The working-pressure rating 
of each BOP component must exceed maximum anticipated surface 
pressures. The BOP system includes the BOP stack and associated BOP 
systems and equipment.


Sec. 250.441  What are the requirements for a surface BOP stack?

    (a) When you drill with a surface BOP stack, you must install the 
BOP system before drilling below surface casing. The surface BOP stack 
must have at least four remote-controlled, hydraulically operated BOPs, 
consisting of an annular preventer, two preventers equipped with pipe 
rams, and one preventer equipped with blind or blind-shear rams.
    (b) One year after the effective date of this final rule, the 
surface BOP stack must have at least four remote-controlled, 
hydraulically operated BOPs consisting of an annular preventer, two 
preventers equipped with pipe rams, and one preventer equipped with 
blind-shear rams.
    (c) In addition to the stack, you must install the associated BOP 
systems and equipment required by the regulations in this subpart.


Sec. 250.442  What are the requirements for a subsea BOP stack?

    (a)(1) When you drill with a subsea BOP stack, you must install the 
BOP system before drilling below surface casing. The District 
Supervisor may require you to install a subsea BOP system before 
drilling below the conductor casing if proposed casing setting depths 
or local geology indicate the need.
    (2) Your subsea BOP stack must have at least four remote-
controlled, hydraulically operated BOPs consisting of an annular 
preventer, two preventers equipped with pipe rams, and one preventer 
equipped with blind-shear rams.
    (3) In addition to the subsea stack, you must install the 
associated BOP systems and equipment required by the paragraphs below 
and the regulations in this subpart.
    (b) You must install a subsea accumulator closing unit 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 subsea accumulator must meet or exceed the provisions of 
Section 13.3, Accumulator Volumetric Capacity, in API RP 53, 
Recommended Practice for Blowout Prevention Equipment Systems for 
Drilling Wells. The District Supervisor may approve a suitable 
alternate method.
    (c) The subsea BOP system must include an operable dual-pod control 
system to ensure proper and independent operation of the BOP system.
    (d) Before removing the marine riser, you must displace the riser 
with seawater. You must maintain sufficient hydrostatic pressure or 
take other suitable precautions to compensate for the reduction in 
pressure and to maintain a safe and controlled well condition.


Sec. 250.443  What associated BOP systems and related equipment must my 
BOP system include?

    (a) An accumulator system that provides 1.5 times the volume of 
fluid capacity necessary to close and hold closed all BOP components. 
The system must perform with a minimum pressure of 200 psi above the 
precharge pressure without assistance from a charging system. If you 
supply the accumulator regulators by rig air and do not have a 
secondary source of pneumatic supply, you must equip the regulators 
with manual overrides or other devices to ensure capability of 
hydraulic operations if rig air is lost.
    (b) 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.
    (c) 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.
    (d) 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.
    (e) A choke and a kill line on the BOP stack. You must equip each 
line with two full-opening valves with at least one remote-controlled 
valve on each line. 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, you may install a check valve on the 
kill line instead of the remote-controlled valve. To use this check 
valve, both manual valves must be readily accessible, and you must 
install the check valve between the manual valves and the pump.
    (f) A fill-up line above the uppermost preventer.
    (g) Locking devices installed on the ram-type preventers.
    (h) A wellhead assembly with a rated working pressure that exceeds 
the anticipated surface pressure.


Sec. 250.444  What are the choke manifold requirements?

    (a) Your BOP system must include a choke manifold that is suitable 
for the anticipated surface pressures, anticipated methods of well 
control, the surrounding environment, and the corrosiveness, volume, 
and abrasiveness of drilling fluids and well fluids that you may 
encounter.
    (b) Manifold components must have a rated working pressure at least 
as great as the rated working pressure of the ram BOPs. If your 
manifold has buffer tanks downstream of choke assemblies, you must 
install isolation valves on any bleed lines.
    (c) Valves, pipes, flexible steel hoses, and other fittings 
upstream of the choke

[[Page 38470]]

manifold must have a rated working pressure at least as great as the 
rated working pressure of the ram BOPs.


Sec. 250.445  What are the requirements for kelly cocks, inside BOPs, 
and drill-string safety valves?

    You must use or provide the following BOP equipment during drilling 
operations:
    (a) A kelly cock installed below the swivel (upper kelly cock);
    (b) A kelly cock installed at the bottom of the kelly (lower kelly 
cock). You must be able to strip the lower kelly cock 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 cock above, and one strippable kelly 
cock 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-cock-type valve below the remote-
controlled valve;
    (e) An inside BOP in the open position located on the rig floor. 
You must be able to install an inside BOP for each size connection in 
the drill string;
    (f) A drill-string safety valve in the open position located on the 
rig floor. You must have a drill-string safety valve available for each 
size connection in the drill string;
    (g) When running casing, you must have a safety valve in the open 
position available on the rig floor to fit the casing string being run 
in the hole;
    (h) All required manual and remote-controlled kelly-cock valves, 
drill-string safety valves, and comparable-type valves in a top-drive 
system must be essentially full-opening; and
    (i) The drilling crew must have ready access to a wrench to fit 
each manual valve.


Sec. 250.446  What must I do to maintain and inspect my BOP?

    (a) You must maintain your BOP system to ensure that the equipment 
functions properly. BOP maintenance must meet or exceed the provisions 
of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, 
Maintenance; and Sections 17.12 and 18.12, Quality Management, 
described in API RP 53, Recommended Practice for Blowout Prevention 
Equipment Systems for Drilling Wells.
    (b) You must visually inspect your surface BOP system on a daily 
basis. You must visually inspect your subsea BOP system and marine 
riser at least once every 3 days if weather and sea conditions permit. 
You may use television cameras to inspect subsea equipment.


Sec. 250.447  When must I conduct BOP system pressure tests?

    You must pressure test your BOP system (this includes the choke 
manifold, kelly cocks, inside BOP, and drill-string safety valve):
    (a) When installed;
    (b) Before 14 days have elapsed since your last BOP pressure test. 
You must begin to test your BOP system before midnight on the 14th day 
following the conclusion of the previous test. However, the District 
Supervisor may require more frequent testing if conditions or BOP 
performance warrant; and
    (c) Before drilling out each string of casing or a liner. The 
District Supervisor may allow you to omit this test if you didn't 
remove the BOP stack to run the casing string or liner and the required 
BOP test pressures for the next section of the hole are not greater 
than the test pressures for the previous BOP test. You must indicate in 
your APD which casing strings and liners meet these criteria.


Sec. 250.448  What are the BOP pressure tests requirements?

    When you pressure test the BOP system, you must conduct a low-
pressure and a high-pressure test for each BOP component. You must 
conduct the low-pressure test before the high-pressure test. Each 
individual pressure test must hold pressure long enough to demonstrate 
that the tested component(s) holds the required pressure. Required test 
pressures are as follows:
    (a) Low-pressure test. All low-pressure tests must be between 200 
and 300 psi. Any initial pressure above 300 psi must be bled back to a 
pressure between 200 and 300 psi before starting the test. If the 
initial pressure exceeds 500 psi, you must bleed back to zero and 
reinitiate the test.
    (b) High-pressure test for ram-type BOPs, the choke manifold, and 
other BOP components. The high-pressure test must equal the rated 
working pressure of the equipment or be 500 psi greater than your 
calculated maximum anticipated surface pressure (MASP) for the 
applicable section of hole. Before you may test BOP equipment to the 
MASP plus 500 psi, the District Supervisor must have approved those 
test pressures in your APD.
    (c) High pressure test for annular-type BOPs. The high pressure 
test must equal 70 percent of the rated working pressure of the 
equipment.
    (d) Duration of pressure test. Each test must hold the required 
pressure for 5 minutes. However, for surface BOP systems and surface 
equipment of a subsea BOP system, a 3-minute test duration is 
acceptable if you record your test pressures on the outermost half of a 
4-hour chart, on a 1-hour chart, or on a digital recorder. If the 
equipment does not hold the required pressure during a test, you must 
correct the problem and retest the affected component(s).


Sec. 250.449  What additional BOP testing requirements must I comply 
with?

    (a) Use water to test a surface BOP system;
    (b) Stump test a subsurface BOP system before installation. You 
must use water to conduct this test. You may use drilling fluids to 
conduct subsequent tests of a subsea BOP system;
    (c) Alternate tests between control stations and pods;
    (d) Pressure test the blind or blind-shear ram during stump tests 
and at all casing points;
    (e) The interval between any blind or blind-shear ram pressure 
tests may not exceed 30 days;
    (f) Pressure test variable bore-pipe rams against all sizes of pipe 
in use, excluding drill collars and bottom-hole tools;
    (g) Pressure test affected BOP components following the 
disconnection or repair of any well-pressure containment seal in the 
wellhead or BOP stack assembly;
    (h) Function test annulars and rams every 7 days between pressure 
tests; and
    (i) Actuate safety valves assembled with proper casing connections 
before running casing.


Sec. 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 certify (sign and date) 
BOP test charts and reports as correct;
    (c) Document the sequential order of BOP and auxiliary equipment 
testing and the pressure and duration of each test. For subsea BOP 
systems, you must also record the closing times for annular and ram 
preventers. You may reference a BOP test plan if it is available at the 
facility;
    (d) Identify the control station or 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;
    (f) Retain all records, including pressure charts, driller's 
report, and

[[Page 38471]]

referenced documents pertaining to BOP tests, actuations, and 
inspections at the facility for the duration of drilling; and
    (g) After drilling is completed, you must retain all the records 
listed in this section for a period of 2 years at the facility, at the 
lessee's field office nearest the facility, or at another location 
conveniently available to the District Supervisor.


Sec. 250.451  How do I remedy BOP problems and situations?

    The table in this section describes remedies to problems and 
situations that lessees encounter with BOP systems on a regular basis 
during drilling activities.

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

Drilling Fluid Requirements


Sec. 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.


Sec. 250.456  What are the required safe drilling fluid program 
practices?

    Your drilling fluid program must include the following safe 
practices:
    (a) Before starting out of the hole with drill pipe, you must 
properly condition the drilling fluid. You must circulate a volume of 
drilling fluid equal to the annular volume with the drill pipe just 
off-bottom. You may omit this practice if documentation in the 
driller's report shows:
    (1) No indication of formation fluids influx before starting to 
pull the drill pipe from the hole;
    (2) The weight of returning drilling fluid is within 0.2 pounds per 
gallon (1.5 pounds per cubic foot) of the drilling fluid entering the 
hole; and
    (3) Other drilling fluid properties are within the limits 
established by the program approved in the APD.
    (b) Record each time you circulate drilling fluid in the hole in 
the driller's report;
    (c) When coming out of the hole with drill pipe, you must fill the 
annulus with drilling fluid before the hydrostatic pressure decreases 
by 75 psi, or every five stands of drill pipe, whichever gives a lower 
decrease in hydrostatic pressure. You must calculate the number of 
stands of drill pipe and drill collars that you may pull before you 
must fill the hole. You must also calculate the equivalent drilling 
fluid volume needed to fill the hole. Both sets of numbers must be 
posted near the driller's station. You must use a mechanical, 
volumetric, or electronic device to measure the drilling fluid required 
to fill the hole;
    (d) You must run and pull drill pipe and downhole tools at 
controlled rates so you do not swab or surge the well;
    (e) When there is an indication of swabbing or influx of formation 
fluids, you must take appropriate measures to control the well. You 
must circulate and condition the well, on or near-bottom, unless well 
or drilling-fluid conditions prevent running the drill pipe back to the 
bottom;
    (f) You must calculate and post near the driller's console the 
maximum pressures that you may safely contain under a shut-in BOP for 
each casing string. The pressures posted must consider the surface 
pressure at which the formation at the shoe would break down, the rated 
working pressure of the BOP stack, and 70 percent of casing burst (or 
casing test as approved by the District Supervisor). As a minimum, you 
must post the following two pressures:
    (1) The surface pressure at which the shoe would break down. This 
calculation must consider the current drilling fluid weight in the 
hole; and
    (2) The lesser of the BOP's rated working pressure or 70 percent of 
casing-burst pressure (or casing test otherwise approved by the 
District Supervisor);
    (g) You must install an operable drilling fluid-gas separator and 
degasser before you begin drilling operations. You must maintain this 
equipment throughout the drilling of the well;
    (h) Before pulling drill-stem test tools from the hole, you must 
circulate or reverse-circulate the test fluids in the hole. If 
circulating out test fluids is not feasible, you may bullhead test 
fluids out of the drill-stem test string and tools with an appropriate 
kill weight fluid; and
    (i) 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.


Sec. 250.457  What equipment must I have to test and monitor drilling 
fluids?

    (a) You must have and maintain drilling fluid-testing equipment on 
the drilling rig at all times. You must test the drilling fluid at 
least once each tour, or more frequently if conditions warrant. You 
must perform the tests according to industry-accepted practices. Tests 
must include density, viscosity, and gel strength; hydrogenion

[[Page 38472]]

concentration; filtration; and any other tests the District Supervisor 
requires. You must record the results of these tests in the drilling 
fluid report.
    (b) Once you establish drilling fluid returns, you must install and 
maintain the following drilling fluid-system monitoring equipment 
throughout subsequent drilling operations. This equipment must have the 
following indicators on the rig floor:
    (1) Pit level indicator to determine drilling fluid-pit volume 
gains and losses. This indicator must include both a visual and an 
audible warning device;
    (2) Volume measuring device to accurately determine drilling fluid 
volumes required to fill the hole on trips;
    (3) Return indicator devices that indicate the relationship between 
drilling fluid-return flow rate and pump discharge rate. This indicator 
must include both a visual and an audible warning device; and
    (4) 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.


Sec. 250.458  What quantities of drilling fluids are required?

    (a) You must use, maintain, and replenish quantities of drilling 
fluid and drilling fluid materials at the drill site as necessary to 
ensure well control. You must determine those quantities based on known 
or anticipated drilling conditions, rig storage capacity, weather 
conditions, and estimated time for delivery.
    (b) You must record the daily inventories of drilling fluid and 
drilling fluid materials, including weight materials and additives in 
the drilling fluid report.
    (c) If you do not have sufficient quantities of drilling fluid and 
drilling fluid material to maintain well control, you must suspend 
drilling operations.


Sec. 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. In areas where 
dangerous concentrations of combustible gas may accumulate, you must 
install and maintain a ventilation system and gas monitors. Drilling 
fluid-handling areas must have the following safety equipment:
    (a) A ventilation system capable of replacing the air once every 5 
minutes or 1.0 cubic feet of air-volume flow per minute, per square 
foot of area, whichever is greater.
    In addition:
    (1) If natural means provide adequate ventilation, then a 
mechanical ventilation system is not necessary;
    (2) If a mechanical system does not run continuously, then it must 
activate when gas detectors indicate the presence of 1 percent or more 
of combustible gas by volume; and
    (3) If discharges from a mechanical system may be hazardous, then 
you must maintain the drilling fluid-handling area at a negative 
pressure. You must protect the negative pressure area by using at least 
one of the following: a pressure-sensitive alarm, open-door alarms on 
each access to the area, automatic door-closing devices, air locks, or 
other devices approved by the District Supervisor;
    (b) Gas detectors and alarms except in open areas where adequate 
ventilation is provided by natural means. You must test and recalibrate 
gas detectors quarterly. No more than 90 days may elapse between tests;
    (c) Explosion-proof or pressurized electrical equipment to prevent 
the ignition of explosive gases. Where you use air for pressuring 
equipment, you must locate the air intake outside of and as far as 
practicable from hazardous areas; and
    (d) Alarms that activate when the mechanical ventilation system 
fails.

Other Drilling Requirements


Sec. 250.460  What are the requirements for well testing?

    (a) 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.
    (b) If you intend to conduct a well test, you must include your 
projected plans for well testing with your APD (form MMS-123) or as a 
Sundry Notice and Reports on Wells (form MMS-124). Your plans must 
include at least the following information:
    (1) Estimated flowing and shut-in tubing pressures;
    (2) Estimated flow rates and cumulative volumes;
    (3) Time duration of flow, buildup, and drawdown periods;
    (4) Description and rating of surface and subsurface test 
equipment;
    (5) Schematic drawing, showing the layout of test equipment;
    (6) Description of safety equipment, including gas detectors and 
fire-fighting equipment;
    (7) Proposed methods to handle or transport produced fluids; and
    (8) Description of the test procedures.
    (c) You must give the District Supervisor at least 24-hours notice 
before starting a well test.


Sec. 250.461  What are the requirements for directional and inclination 
surveys?

    For this subpart, MMS classifies a well as vertical if the 
calculated average of inclination readings does not exceed 3 degrees 
from the vertical.
    (a) Survey requirements for a vertical well: (1) You must conduct 
inclination surveys on each vertical well and digitally 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:
    (i) Within 500 feet of setting surface or intermediate casing;
    (ii) Within 500 feet of setting any liner; and
    (iii) When you reach total depth.
    (b) Survey requirements for directional well: You must conduct 
directional surveys on each directional well and digitally record the 
results. Surveys must give both inclination and azimuth at intervals 
not to exceed 500 feet during the normal course of drilling. Intervals 
during angle-changing portions of the hole may not exceed 100 feet.
    (c) Measurement while drilling. You may use measurement-while-
drilling technology if it meets the requirements of this section.
    (d) Composite survey requirements:
    (1) Your composite directional survey must show the interval from 
the bottom of the conductor casing to total depth. In the absence of 
conductor casing, the survey must show the interval from the bottom of 
the drive or structural casing to total depth; and
    (2) You must correct all surveys to Universal-Transverse-Mercator-
Grid-north or Lambert-Grid-north after making the magnetic-to-true-
north correction. Surveys must show the magnetic and grid corrections 
used and include a listing of the directionally computed inclinations 
and azimuths.
    (e) If you drill within 500 feet of an adjacent lease, the Regional 
Supervisor may require you to furnish a copy of the well's directional 
survey to the affected leaseholder.

[[Page 38473]]

Sec. 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 that is applicable for the well. Your plan must outline the 
assignments for each crew member and establish times to complete each 
portion of the drill. You must post a copy of the well control drill 
plan on the rig floor or bulletin board.
    (b) Timing of drills. You must conduct each drill during a period 
of activity that minimizes the risk to drilling operations. The timing 
of your drills must cover a range of different operations, including 
drilling with a diverter, on-bottom drilling, and tripping.
    (c) Recordkeeping requirements. For each drill, you must record the 
following in the driller's report:
    (1) The time to be ready to close the diverter or BOP system; and
    (2) The total time to complete the entire drill.
    (d) MMS ordered drill. An MMS authorized representative may require 
you to conduct a well control drill during an MMS inspection. The MMS 
representative will consult with you before requiring the drill.


Sec. 250.463  Who establishes field drilling rules?

    (a) The District Supervisor may establish field drilling rules 
different from the requirements of this subpart when geological and 
engineering information shows that specific operating requirements are 
appropriate. You must comply with field drilling rules and 
nonconflicting requirements of this subpart. The District Supervisor 
may amend or cancel field drilling rules at any time.
    (b) You may request the District Supervisor to establish, amend, or 
cancel field drilling rules.

Sundry Notices and Well Records


Sec. 250.465  When must I submit sundry notices to MMS?

    (a) You must submit sundry notices (form MMS-124) and other 
materials to the Regional Supervisor as shown in the following table. 
You must also submit a public information copy of each form.

----------------------------------------------------------------------------------------------------------------
              If you . . .                    then you must . . .                      and . . .
----------------------------------------------------------------------------------------------------------------
(1) Intend to revise plans, change major  submit form MMS-124 or       receive written or oral approval from the
 drilling equipment, deepen, plug-back,    request oral approval.       District Supervisor before you begin the
 or sidetrack a well.                                                   intended operation. If you get an oral
                                                                        approval, you must submit form MMS-124
                                                                        within 72 hours. In all cases, you must
                                                                        meet the additional requirements in
                                                                        paragraph (b) of this section.
(2) Sidetrack...........................  submit a form MMS-124......  include the reason for the sidetrack,
                                                                        kickoff point, and applicable
                                                                        information as required for an APD
                                                                        (Secs.  250.411 through 250.418)
(3) Determine that a well's final         immediately submit a form    submit a plat that meets the requirements
 surface location, water depth, or the     MMS-124.                     of Sec.  250.412
 rotary kelly bushing elevation is
 different than permitted.
(4) Move a drilling unit from a wellbore  submit forms MMS-124 and     submit appropriate copies of the well
 before completing a well.                 MMS-125 (Well Summary        records.
                                           Report) within 30 days
                                           after the suspension of
                                           wellbore operations.
----------------------------------------------------------------------------------------------------------------

    (b) If you intend to perform any of the actions specified in 
paragraph (a)(1) of this section, you must meet the following 
additional requirements:
    (1) Your form MMS-124 must contain a detailed statement of the 
proposed work that will materially change from the approved APD;
    (2) Your form MMS-124 must include the present status of the well, 
depth of all casing strings set to date, well depth, present production 
zones and productive capability, and all other information specified; 
and
    (3) Within 30 days after completing this work, you must submit form 
MMS-124 with detailed information about the work to the District 
Supervisor unless you have already provided sufficient information in a 
weekly Activity Report, form MMS-133 (Sec. 250.467(c)).


Sec. 250.466  What well records must I keep?

    You must keep complete, legible, and accurate records for each 
well. You must keep these records at your field office nearest the OCS 
facility or at another location conveniently available to the District 
Supervisor. The records must contain complete information on all of the 
following:
    (a) Well operations;
    (b) Descriptions of formations penetrated;
    (c) Content and character of oil, gas, water, and other mineral 
deposits in each formation;
    (d) Kind, weight, size, grade, and setting depth of casing;
    (e) All well logs and surveys run in the wellbore;
    (f) Any significant malfunction or problem; and
    (g) All other information required by the District Supervisor.


Sec. 250.467  What well records may I be required to submit?

    The Regional or District Supervisor may require you to submit 
copies of all the well records listed in this section.
    (a) Well operations as specified in Sec. 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 and format for this information.
    (c) Daily drilling reports. For drilling operations in the GOMR, 
you must provide this information on a weekly basis using form MMS-133, 
weekly Activity Report.
    (d) Service company reports on cementing, perforating, acidizing, 
testing, or other similar services.
    (e) Other reports and records of operations.


Sec. 250.468  How long must I keep drilling-related records?

    You must keep records for the time periods shown in the following 
table.

[[Page 38474]]



------------------------------------------------------------------------
You must keep records relating to .
                . .                              until . . .
------------------------------------------------------------------------
(a) Drilling.......................  90 days after you complete drilling
                                      operations
(b) Casing and liner pressure        2 years after the completion of
 tests, diverter tests, and BOP       drilling operations
 tests.
(c) Completion of a well or of any   you permanently plug and abandon
 workover activity that materially    the well or until you forward the
 alters the completion                records with a lease assignment.
 configuration or affects a
 hydrocarbon-bearing zone.
------------------------------------------------------------------------

Sec. 250.469  Must I submit copies of well logs?

    You must submit copies (field or final prints of individual runs) 
of logs or charts of electrical, radioactive, sonic, and other well-
logging operations; directional-and vertical-well surveys; velocity 
profiles and surveys, and analysis of cores to MMS. Each Region will 
provide specific instructions for submitting well logs and surveys.
* * * * *
    4. In Sec. 250.515, paragraph (b) is revised to read as follows:


Sec. 250.515  Blowout prevention equipment.

* * * * *
    (b) The minimum BOP system for well-completion operations must meet 
the appropriate standards from the following table:

----------------------------------------------------------------------------------------------------------------
                       When . . .                                the minimum BOP stack must include . . .
----------------------------------------------------------------------------------------------------------------
(1) The expected pressure is less than 5,000 psi.......  three preventers consisting of: an annular, one set of
                                                          pipe rams, and one set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or greater or     four preventers consisting of: an annular, two sets of
 you use multiple tubing strings.                         pipe rams, and one set of blind or blind-shear rams.
(3) You handle multiple tubing strings simultaneously..  four preventers consisting of: an annular, one set of
                                                          pipe rams, one set of dual pipe rams, and one set of
                                                          blind or 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) It is one year from the final rule effective date..  at least one set of blind-shear rams.
----------------------------------------------------------------------------------------------------------------

* * * * *
    5. In Sec. 250.615, paragraph (b) is revised to read as follows:


Sec. 250.615  Blowout prevention equipment.

* * * * *
    (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 preventers consisting of: an annular, one set of
                                                          pipe rams, and one set of blind or blind-shear rams.
(2) The expected pressure is 5,000 psi or greater or     four preventers consisting of: an annular, two sets of
 you use multiple tubing strings.                         pipe rams, and one set of blind or blind-shear rams.
(3) You handle multiple tubing strings simultaneously..  four preventers consisting of: an annular, one set of
                                                          pipe rams, one set of dual pipe rams, and one set of
                                                          blind or 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) It is one year from the final rule effective date..  at least one set of blind-shear rams.
----------------------------------------------------------------------------------------------------------------

Hydrogen Sulfide

* * * * *
[FR Doc. 00-15546 Filed 6-20-00; 8:45 am]
BILLING CODE 4310-MR-P


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