[Federal Register Volume 59, Number 93 (Monday, May 16, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-11601]
[[Page Unknown]]
[Federal Register: May 16, 1994]
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DEPARTMENT OF THE INTERIOR
Minerals Management Service
30 CFR Part 250
RIN 1010-AB52
Safety Requirements Governing Production Platforms and Pipelines
AGENCY: Minerals Management Service, Interior.
ACTION: Proposed rule.
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SUMMARY: This rule proposes to revise various safety-related
regulations regarding the design and operating procedures of production
platforms and pipelines in the Outer Continental Shelf (OCS). The
purpose of the revisions is to reduce or prevent the unintentional
release of hydrocarbons from pipelines on or near offshore platforms
during emergency situations and thereby reduce the potential for
explosions or fires.
DATES: Comments must be received or postmarked no later than July 15,
1994.
ADDRESSES: Comments should be mailed or hand-carried to the Department
of the Interior, Minerals Management Service, Mail Stop 4700, 381 Elden
Street, Herndon, Virginia 22070-4817; Attention: Chief, Engineering and
Standards Branch.
FOR FURTHER INFORMATION CONTACT: Paul Schneider, Technology Assessment
and Research Branch, telephone (703) 787-1559, or Bill Hauser,
Engineering and Standards Branch, telephone (703) 787-1600.
SUPPLEMENTARY INFORMATION:
Background
The MMS is proposing to revise regulations governing design,
operation, and maintenance of oil and gas facilities in the OCS. These
revisions were recommended by an internal task group that reviewed
information on tow tragic offshore incidents in 1988 and 1989.
Safety Review Task Group
A safety review task group of MMS personnel was established to
review available information in the 1988 Piper Alpha platform fire in
the North Sea and the circumstances related to an interactive pipeline
and platform fire in 1989 at ARCO Oil and Gas Company's (ARCO) South
Pass 60 Platform ``B'' facility in the Gulf of Mexico. The group was
asked to make specific recommendations regarding regulations and
operating practices that would reduce the risk of such incidents
occurring in U.S. waters. Following is a capsule summary of each
incident.
Explosion and Fire on Piper Alpha Platform, North Sea, 1988
Piper Alpha was an oil and gas production platform in the United
Kingdom (U.K.) sector of the North Sea that was destroyed by fire in
1988. On July 6, 1988, a series of events and operational mistakes
caused an explosion and fires that ultimately destroyed the platform
and killed 167 people. Maintenance personnel mistakenly activated an
out-of-service injection pump causing a repair flange in the pipework
to rupture. Liquid condensate leaked into the production module for
several minutes. The gas ignited and exploded, damaging the electrical
power generator and the fire pumps. Eventually the fire ruptured the
shut-in gas pipelines releasing high pressure gas on the platform. The
fire burned for several hours until the pressure was relieved. The
platform was completely destroyed.
The Public Inquiry into the Piper Alpha Disaster was published by
Her Majesty's Stationery Office, London, in November 1990. The report
confirmed the conclusions reached in the initial investigation report
published in September 1988. The report concluded that in all
likelihood the scenario of the leaking blind flange in the condensate
injector pump was the initial cause of the incident. The report lists
106 recommendations for improving safety in the U.K. North Sea. The
recommendations propose changes to the regulations, regulatory agency
realignment, and a call for renewed commitment to safety by industry.
Summary of South Pass 60 Platform ``B'' Fire
On March 19, 1989, an offshore contracting crew was ``cold-
cutting'' an 18-inch gas line riser at the platform's 10-foot level in
preparation for the installation of a pig trap. ``Cold cutting'' is a
method of cutting through a section of pipe with a mechanical cutting
tool as opposed to using a blow torch. Upon penetration into the
pipeline riser, pressurized condensate began to spray from the cut
area. The condensate was ignited either by sparks generated on the
compressor skid on an attendant workboat or by hot exhaust pipes on the
above production deck. The fire raged upward from the riser, and the
emergency shutdown (ESD) system shut down both Platform ``B'' and
Platform ``E'' and all incoming and departing pipelines. Six of the 10
incoming and departing pipelines, including a high pressure gas line,
ruptured from the heat of the fire. The resulting explosions killed
seven people and destroyed the platform.
Federal Register Notice on Subsea Pipeline Valves
In support of the work of the task group, MMS published a Federal
Register Notice dated July 23, 1990 (55 FR 29860), seeking information
on subsea shutdown valve (SDV) technology and feasibility and offshore
emergency pipeline pressure reduction techniques. Thirty companies and
organizations representing oil- and gas-related industries responded to
the questionnaire. Their responses are discussed later in the preamble.
Task Group Findings
The MMS task group identified the following areas in the
regulations that should be revised:
1. Identification and notification procedures for out-of-service
safety devices and systems.
2. Location and protection of pipeline risers.
3. Diesel and helicopter fuel storage areas and tanks.
4. Approval of pipeline repairs.
5. Location of ESD valves on pipelines.
Identification and Notification Procedures for Out-of-Service Safety
Devices
A contributing factor to both accidents was the lack of
communication and notification to personnel of the platform production
systems status. In the Piper Alpha incident, the production crew
attempted to start a condensate injection pump that was partially
dismantled for repairs during the previous shift. Leaking condensate
from the associated pipework of the pump caused the first of a series
of explosions and fires. The location of the pump control panel did not
allow the operator of the control panel to view the pump or detect the
leak. In the South Pass 60 incident, the platform operator and the
pipeline company did not provide for adequate planning and coordination
of the riser cutting operation. Platform personnel were apparently
unaware of the status of the riser cutting operation or the difficulty
the contractor was experiencing with the unexpected flow.
Current regulations for identifying out-of-service devices are
found at:
30 CFR 250.123(c), General platform operations. (1) Surface or
subsurface safety devices shall not be bypassd or blocked out of
service unless they are temporarily out of service for startup,
maintenance, or testing procedures. Only the minimum number of safety
devices shall be taken out of service. Personnel shall monitor the
bypassed or blocked-out functions until the safety devices are placed
back in service. Any surface or subsurface safety device which is
temporarily out of service shall be flagged.
Requirements for out-of-service devices on pipelines are found at
30 CFR 250.154(c). If the required safety equipment is rendered
ineffective or removed from service on pipelines which are continued in
operation, an equivalent degree of safety shall be provided. The safety
equipment shall be identified by the placement of a sign on the
equipment stating that the equipment is rendered ineffective or removed
from service.
The task group determined that the existing regulations do not
provide for adequate communication or warning of out-of-service
equipment and may not have prevented an accident similar to Piper Alpha
if the same set of circumstances existed in the OCS. The current rule
does not ensure that accidental flow of hydrocarbons will not be
initiated in process components that are taken out of service,
particularly if flow is initiated out of view of a flagged device or
control. Flagging requirements for out-of-service equipment and valves
need to be revised to ensure that control panels and certain equipment
upstream of process equipment or valves are also flagged and that the
procedure is documented. The task group recommended that the
regulations should include requirements identifying which individuals
have the authority to remove flags and to authorize equipment startup.
It also recommended that subpart A be revised to include a briefing
requirement to ensure that all workers on a production platform are
notified of all out-of-service equipment and safety concerns at the
beginning of each work shift or upon addition or replacement of
personnel.
Location and Protection of Pipeline Risers
From the evidence gathered on Piper Alpha, at least one of the
highly pressured risers ruptured when struck by debris falling from the
burning platform. The effect of gas escaping from the high pressure
pipeline was catastrophic. The escaping gas boiled to the surface,
exploded, and burned under the platform for several hours.
Subpart J of the regulations currently requires risers to be
protected only from contact with floating vessels. Protection is
usually accomplished by locating risers between the jacket legs or by
reinforcing the risers with external protection. The task group
recommended that subpart J be revised to add a requirement to provide
for riser protection from falling objects as well and that MMS require
submission of piping drawings at an early stage in the platform design
approval process.
Diesel and Helicopter Fuel Storage Areas and Tanks
During the early stages of the Piper Alpha incident, fuel drums and
containers of lubricants and cleaners stored throughout the platform
exploded and burned when they were exposed to flames. These materials
are stored in a similar manner on U.S. facilities.
There are no current MMS regulations for fuel storage. The task
group recommended that MMS revise the regulations to require operators
to store diesel and other flammable liquids on platforms in accordance
with the requirements contained in American Petroleum Institute (API)
Recommended Practice (RP) 500, Recommended Practice for Classification
of Locations for Electrical Installation at Petroleum Facilities. The
task group also recommended that the revised regulations require
operators to design fuel storage tanks in accordance with API RP 14C,
Recommended Practice for Analysis, Design, Installation and Testing of
Basic Surface Safety Systems for Offshore Production Platforms.
Approval of Pipeline Repairs
Upon examination of the events leading to the fire on the ARCO
``B'' platform, the task group found that there was a lack of
communication and coordination between the platform operator and the
pipeline repair company. The task group recommended that the
regulations be strengthened by requiring MMS approval for pipeline
repairs. The Regional Supervisor, upon being notified that the lessee
or right-of-way holder is anticipating a pipeline repair, will consider
the complexity of the repair procedure in deciding whether or not to
require a written repair plan. Exceptions would be made for pipeline
repairs necessitated by imminent harm to the environment or to human
safety.
Location of ESD Valves on Pipelines
The Piper Alpha fire and the Arco ``B'' fire were greatly
intensified by released gas from pipelines associated with the
platforms. In the United States, incoming pipelines are required to
have emergency SDV's as a protective measure, but they are often
located onboard the platform to allow access for maintenance and
testing.
Locating SDV's away from the process equipment, such as on the
seafloor or on the riser close to the waterline, may provide a greater
level of protection for the platform but would at the same time reduce
accessibility for repair and maintenance. This issue has major safety
and reliability implications; therefore, MMS published the advance
notice of proposed rulemaking in the Federal Register requesting more
information on this subject.
Thirty responses to the questionnaire were received from the oil
and gas industry, including major oil and gas production companies,
pipeline operators, and equipment manufacturers. The first 13 questions
dealt with locating a pipeline SDV on the seafloor or just above the
splash zone. Approximately half of the respondents cited limited access
to a valve, particularly those located on the seafloor, for inspection
and maintenance purposes as a major area of concern. Nearly half of the
commenters suggested that the reliability of subsea valves is unknown
or nonexistent. Again, supporting data was very limited. The remaining
four questions dealt with pipeline pressure reduction during emergency
situations. The results of the questionnaire are discussed after this
section.
For applications in the United States, the task group considered
three distinct riser locations for the placement of SDV's: On the
platform, on the seafloor, on the vertical portion of the riser below
the lowest production deck but above the waterline. The advantages and
disadvantages of each location are discussed below:
The first location considered was ``on the platform.'' Subpart J--
Pipelines and Pipeline Rights-of-Way, Sec. 250.154(b)(2) requires that,
Incoming pipelines boarding to a production platform shall be
equipped with an automatic shutdown valve (SDV) immediately upon
boarding the platform * * *
This regulation allows placement of the SDV on the deck where the
riser enters the platform. ``Immediately upon boarding'' means near the
edge of the platform. Accessibility for testing and maintenance is the
greatest advantage to this location since the valve is located within
the platform structure. Also, since the valve is located in close
proximity of the production processing equipment, there is little or no
hydrocarbon inventory between the valve and the process equipment that
needs to be vented in the event of an emergency. However, this location
also presents the greatest potential safety hazard. Since the valve is
located near the process equipment, it is vulnerable to damage from
explosions, extreme heat from fires, and falling debris during
emergency situations. The task group determined that the valve in this
location does not fulfill the intended purpose of an SDV in all
situations since failure of the SDV or pressured portion of the riser
would likely result in the release of a significant portion of the
pipeline inventory at the point of failure. This vulnerability was
demonstrated in the Piper Alpha disaster and the South Pass 60 fire.
Next, the task group considered locating SDV's on the seafloor a
short distance from the platform. The safety advantage of this location
is obvious. The valve is isolated from the platform and is not
vulnerable to explosions or fire that may occur during an emergency
situation. However, a major drawback of this location is
inaccessibility for maintenance and testing, especially in deep water.
At this location, the valve would isolate the majority of the pipeline
inventory from the platform. However, there may be a significant
hydrocarbon inventory in the riser between the valve on the seafloor
and the process equipment. This inventory must be safely vented when
the pipeline is depressurized during an emergency after the valve is
closed.
Lastly, the task group considered locating SDV's on the vertical
portion of risers below the lowest production deck of the platform but
above the waterline. This location offers several advantages. The valve
is removed from and placed below the hydrocarbon process areas within
the platform, thereby isolating it from potential explosion and fire
damage during emergency situations. Also, it effectively isolates the
entire inventory of the pipeline from the platform since there is a
minimal length of riser between the valve and the process equipment
that must be vented during emergency situations, and the valve is above
the waterline and is accessible for maintenance and testing.
Considering the information gathered from the Federal Register
Notice and additional information regarding subsea valve installations
in the U.K. North Sea, the task group concluded that locating such
valves on risers or on the seafloor was technically feasible. Other
aspects of the current regulation were also reviewed. The task group
considered the current regulation which requires SDV's to be installed
on incoming pipelines only. Based on the events that occurred on Piper
Alpha, the task group determined that there is a significant potential
hazard from blackflow of pressured hydrocarbons from departing
pipelines. Therefore, the task group recommended requiring SDV's on all
new pipelines entering and departing production platforms. This
requirement should also apply to sulphur operations since sulphur is
also flammable and poses a significant threat to safety. This
requirement would cover bidirectional pipelines, crossing pipelines,
fuel lines, and pipelines carrying flammable or hazardous fluids.
Crossing pipelines that enter onto platforms but do not take on
production from those platforms pose an environmental risk, if not a
risk to human safety. Therefore, crossing pipelines should also be
required to have SDV's installed on the incoming and departing risers.
Responses to the Questions in the July 23, 1990, Federal Register
Notice
The following represents a summary of the responses received and
does not necessarily reflect the opinion of MMS.
Question--If the SDV was located on the seafloor or just above the
splash zone, how would the following parameters be affected?
(a) Maintenance.
Response--Subsea maintenance poses a major problem, especially for
deep water which would be difficult during rough seas and winter
months. This jeopardizes the operation of the pipeline during those
periods. Preventative subsea maintenance would be impractical while
maintenance by divers would pose an additional safety risk. Minor and
major repairs of a valve would most likely require removal from the
pipe which is dangerous in itself and would require shutting down the
pipeline system for extended periods.
The splash zone is the most corrosive offshore environment. The
cyclical wetting and drying of surface materials accelerate the
corrosion process and degrades protective coatings. At the splash zone,
increased maintenance would be required and most platforms have limited
access in this area. Splash zone maintenance could not be performed
during rough seas or winter months, thus jeopardizing the operation of
the pipeline during those periods. Control lines would also be exposed
to the corrosive wet/dry environment. Requiring SDV's to be located
subsea or at the splash zone increases the safety risk to personnel and
reduces the pipeline system's reliability.
The diving cost alone to repair a subsea SDV in 180 feet of water
would run between $15,000 and $18,000 per day.
(b) Inspection.
Response--Subsea SDV inspection by a diver would be of minimal
value. Control systems for subsea valves are more complex than for
surface valves. The ability of divers to inspect and perform repairs
underwater is questionable and cannot be verified. Inspection and
repair operations would be limited by weather conditions.
Inspection of an SDV above the splash zone is reliable since it can
be performed by an engineer or company representative. All inspection
information is first hand.
A typical subsea SDV inspection in 300 feet of water could cost
between $20,000 and $30,000 per day.
(c) Testing.
Response--Testing subsea valves from a remote station is not
reliable and may indicate problems that may or may not exist.
Dealing with a malfunction during testing could have serious
implications due to limited accessibility.
The higher the SDV is located above the water, the greater its
accessibility, maintenance, and performance.
Frequency of subsea SDV testing should be kept to a minimum in
order to maintain valve reliability.
Testing would be complex. Remote monitoring or divers would be
necessary to confirm test results.
(d) Reliability.
Response--Reliability is dependent on the individual reliability of
all the components that make up the SDV and control system. Subsea
valve reliability statistics are not presently available and need to be
established.
It is assumed that the reliability of an SDV functioning on the
seafloor would be less than at any other location. Access to the SDV
and control lines would be limited and equipment and personnel would be
exposed to adverse conditions.
The reliability of an SDV functioning in the splash zone would be
slightly higher. Accessibility would be improved but the valve itself
and control lines would be exposed to more adverse conditions.
(e) Pressure venting.
Response--Subsurface SDV's would be limited by the static back
pressure of the seawater, or vent lines to the surface would be
required. This may cause a delay in response time.
A splash zone SDV would not have back pressure, but gas exhaust
would need to be routed to the platform vent system.
Underwater venting of pipelines is not recommended due to
environmental considerations.
The volume of hydrocarbons vented through the platform flare system
would be greater for a subsea SDV than a platform SDV. This is a
serious safety consideration.
The capability to vent pressure from a pipeline should never take
the form of bypassing the SDV but should be from the respective ends of
the pipelines.
(f) Bidirectional operations.
Response--Not affected.
(g) Pigging operations.
Response--Subsea valves should be fitted with remote position
indicators to ensure the valve is fully open during pigging operations.
Question--What measures could be taken to enhance performance and
reliability--in particular, how could problems identified in response
to question one be alleviated?
Response--Locating the SDV above the maximum wave height would
alleviate most problems described in question one. Control lines are
relatively short and the valve is readily accessible for maintenance
and repairs.
There are designs where safety can be achieved by other methods.
There are also ``economical'' platforms where the producer accepts more
risk to reduce facility costs. The location of the SDV should be
commensurate with the level of protection afforded to other high-risk
facilities on the platform.
The SDV's should be manufactured from materials which will avoid
valve replacement and offer reliable performance. The valve should have
manual actuators and quick connect ends to facilitate operation or
removal.
Platform operating decks should be made of plate, not grating.
Plate acts as a fire wall. If the deck is made of plate, the SDV can be
safely located on the deck.
The SDV's should be self-operating and fail-safe closed.
Valves should be routinely inspected and tested as well as
continuously monitored.
The SDV and control system should be protected from mechanical
damage.
Placement of SDV's on the platform would improve reliability but
would also minimize their effectiveness.
Redundant control and instrumentation systems may be desirable.
Standards should be established for value specifications and
certification. Quality control in manufacturing could also enhance
their reliability.
Valve technology has advanced to the point that reliable subsea
operation is available. Advancement in the areas of a valve failure
data base and check valve technology could yield further reliability
and performance.
Require a surface SDV as well as a subsea valve.
Question--What types of SDV's are available that could be located
on the seafloor?
Response--Any valve designed for subsea service such as a quarter
turn ball valve, check valve, or a gate valve could perform as an SDV.
The use of hydraulically operated valves could present a pollution
problem.
It is the actuator that needs to be scrutinized.
No existing SDV would likely serve the purpose when located on the
seafloor.
Hydraulic or pneumatic systems would be most practical. Some
manufacturers have devised an SDV for subsea service.
Question--What specific limitations would be encountered with
regard to placing the SDV at the seafloor location with respect to the
following variables?
(a) Size of valve.
Response--For the most part, the size of the valve is not a major
factor. However, valves over 12 inches in diameter are cumbersome,
heavy and difficult to maneuver, and maintain. Valves greater than 36
inches in diameter are difficult to obtain.
The valve and actuator may be quite large and may require
mechanical protection.
(b) Pressure.
Response--For the most part, pressure is not a major consideration
except in deep water. Very large actuators may be needed to overcome
extreme differential pressures in deep water.
(c) Flow rate.
Response--For low flow rates, the reduced flow may not justify the
placement of a seafloor SDV.
(d) Water depth.
Response--Water depth has a large effect on diver costs for
installation, maintenance, repairs, testing, etc. Deep-water locations
also require novel installation methods, additional complexity, and
further development of components and testing methods to achieve valve
reliability. Some SDV's may be designed for installation and
maintenance using a drilling rig. Beyond, 1,000 feet, diverless
maintenance and retrieval become major considerations. Common valve
operators are limited to water depths of less than 3,000 feet.
In shallow water, subsea valves would be subjected to potential
damage from shipping vessels.
(e) Types of fluids transported.
Response--Gas lines that are pressurized contribute a higher risk
to platform safety than nonpressurized oil lines.
(f) Other variables identified by commenters.
Response--Repairing and replacing subsea SDV's would increase
pollution potential.
Reliable valve operation is the biggest concern. Factors affecting
operation include water pressure and severe water forces on the valve
and operating lines, hydrate formation, wax build up, etc. Chemical
injection may be necessary to prevent hydrate or wax build up.
The use of seafloor SDV's would preclude the use of J-tube methods
of riser installation since the valve could not be passed through the
J-tube.
Sea-bottom conditions may dictate the location of SDV's.
Protective coverage would be necessary to prevent trawl damage.
Heavy valves, should they become suspended, will cause additional
stress on the pipeline.
The SDV's located near the waterline would be vulnerable to
collisions and wave damage.
Question--What actuation and control system options are available
for placement of the SDV on the seafloor (e.g., pneumatic, hydraulic,
electrical)? Would actuation backup capability be necessary or
desirable?
Response--Actuators can be powered by line pressure, stored gas
pressure, or hydraulics. Fail-safe operation would be desirable.
Pneumatic and hydraulic systems are the most reliable for subsea
service. Manual operation is also necessary. Electrical systems could
be used, but a backup system would be desirable. It is also necessary
to provide manual diver valve actuation for emergency situations.
Question--What emergency support systems (e.g., fire loop system,
ESD system, subsurface safety system) would activate the subsea SDV?
Should the conditions of actuation be different than for an SDV located
on the platform?
Response--All ESD and fire loop systems could operate the SDV.
There would need to be a control line between the valve actuator and
the platform. This could pose a maintenance problem. Pressure sensors
could also be installed for the case of a ruptured or blocked line.
This would require a relief valve, which brings up the following
question. Where would the relief valve relieve to, the seafloor? The
foregoing provides yet another reason to have the SDV above water.
Question--For seafloor placement of the SDV, what would be the
optimum location in distance from the platform?
Response--Distance is not very important. The closer to the
platform, the better. This would keep the control lines the shortest.
Placing the valve 40 feet below the water surface on the riser would
make it accessible to divers while providing its structural protection.
The location of an SDV relative to the platform should ideally be
decided by a quantified risk analysis. The optimum distance for
placement of an SDV should be determined on a case-by-case basis,
considering water depth, anchorage areas, fishing areas, and minimizing
the inventory between the platform and the SDV.
Question--What effect would burial (either intentional or
unintentional) of the valve and actuator have on maintenance and
operational reliability?
Response--Burial would not hurt the SDV, but it would make it
harder for divers to find it. Burial would increase the diving costs
associated with maintenance. Burial would preclude using a remotely
operated vehicle for inspection and maintenance and should be avoided.
Question--What measures would be necessary to protect a subsea
valve and control system from the following effects?
(a) Temperature.
Response--The SDV and control system need to be designed to operate
in internal and external environments by selection of suitable
materials.
(b) Hydrates.
Response--Hydrate formation could prevent subsea SDV operation.
Glycol injection lines would be required in addition to control lines
supplemented with glycol tanks, pumps, and attendant equipment.
(c) Permafrost.
Response--Not feasible.
(d) Hydrogen sulfide.
Response--The effects of hydrogen sulfide could be controlled with
special alloys or inhibitors.
(e) Carbon dioxide.
Response--The effects of carbon dioxide could be controlled with
special alloys or inhibitors.
(f) Stress cracking.
Response.--The effects of stress cracking could be controlled with
special alloys.
(g) Other effects identified by commenters.
Response.--Control lines and connections could be damaged by boat
or fishing activity. Protection will be necessary to protect small
lines from being hooked by trawl boats and anchors.
Sand production could jeopardize the operation of a subsea valve.
Corrosion protection will be necessary for valve operators and
control lines.
Question--Should SDV's be manufactured, maintained, and repaired in
accordance with a certification process similar to the process used
with surface and subsurface safety valves?
Response--API Spec 6D, Specification for Pipeline Valves, is a
sufficient standard for valves, so certification is not necessary.
Pipeline SDV's are not critical to permanent containment of
hydrocarbons. However, proper maintenance of subsea valves may be a
bigger issue.
Question--Would the use of flexible piping impose difficulties to
subsea valve?
Response--Not so long as the pipeline is properly anchored at the
valve location. High seas could pose a difficult problem (keeping the
pipe still). Also, special support may be necessary for the SDV.
Question--If an SDV is placed at an alternate seafloor location,
should an ADV also be placed on the platform?
Response--An SDV installed on a platform has a different function
than a subsea SDV. The platform SDV mitigates consequences of a
hydrocarbon release from the process equipment by isolating the
pipeline from those facilities. Subsea SDV's mitigate the consequences
of a hydrocarbon release from the pipeline which may occur as a primary
or secondary event.
In general, redundancy is always safer. However, redundancy costs
more for equipment and increases the chance for malfunction and
platform downtime. Placement of a surface SDV should not be required
but considered an option. In general, SDV's should not be placed on the
seafloor except in unusual circumstances.
If an SDV is installed above the splash zone, there is no need for
another one on the seafloor.
Question--Current regulations require SDV's on certain incoming
pipelines. What, if any, SDV's should be required on outgoing and
crossing pipelines?
Response--There is no need to place SDV's on all outgoing or
crossing pipelines. Adding more valves is not necessary; however,
present valves may need to be relocated to safer locations.
The SDV's should be placed on new outgoing and crossing pipelines.
A risk assessment should be performed on existing lines before making
such modifications.
Flow safety valves are adequate and less likely to fail, due to
their simplistic design.
Unmanned platforms that contain no production facilities, no
compression, and no power source should not require SDV's.
Question--What options are available to allow rapid reduction of
pipeline pressure in an emergency, and what are the benefits and
drawbacks of the techniques?
Response--Rapid reduction of pipeline pressure is a formidable
problem. Flaring at the platform can be a very slow method of reducing
pipeline pressure. Strategically located SDV's along the pipeline may
offer an alternative to depressurization. An outlying subsea vent is
probably safest since it distances the gas from the platform. However,
in most cases, rapid pressure reduction is expensive and of limited
use.
There is the damage of the formation of hydrate plugs and liquid
plug flow as well as the need to prevent expanding vapor explosions.
Blowdown on the seafloor or a platform could cause considerable
pollution due to entrained liquids and could feed a fire in some
instances.
Blowing down a pipeline at a platform would require a scrubber
system to separate liquids. These liquids would need to be disposed of
safely which may be difficult during a platform emergency.
Question--What are the benefits and shortcomings of subsea pipeline
diversion?
Response--System dependability might be enhanced by subsea
diversion but not enough to offset additional cost over platform
diversion.
Subsea diversion could place evacuating and rescuing personnel in
peril and could pose a significant pollution problem.
Question--What are the advantages and disadvantages of having the
capability to blow down a pipeline from both ends?
Response--It may be good engineering practice to locate blowdowns
at each end of a pipeline. One end may be inaccessible due to fire or
failure. If both ends are accessible, a more rapid blowdown can be
accomplished. However, the majority of damage and injuries on a
platform occurs during the first few minutes and before pressure could
be reduced. Actual damage is not likely to be significantly reduced.
It would be necessary to bypass the check valve of the outgoing
line. The bypass would need to be maintained and tested. Facilities for
large scrubbing, liquid handling, and flaring would also be required.
Question--Should pipelines be required to have the capability of
rapid reduction of pipeline pressure from either end and, if so, what
length of time should be specified as the maximum time for pipeline
pressure reduction in an emergency situation?
Response--Rapid pressure reduction is impractical during
emergencies. Larger lines and volumes must be depressurized more
slowly.
The pest solution is accident prevention and efficient platform
evacuation. Gas pipeline pressure cannot be reduced fast enough to
prevent early damage during a platform emergency.
In an emergency, evacuation is the primary concern. Flaring large
volumes of gas could create a dangerous situation for aircraft and
boats.
Summary of Proposed Changes
Based on the report of the task group and the analysis of the
responses received following the July 23, 1990, Federal Register
Notice, MMS proposes to:
1. Revise Sec. 250.1, Documents incorporated by reference, to
incorporate API's Recommended Practice for Classification of Locations
for Electrical Installation at Petroleum Facilities, First Edition,
June 1, 1991 (API RP 500), into the regulations. This document replaces
API RP 500B, Recommended Practice for Classification of Areas for
Electrical Installations at Drilling Rigs and Production Facilities on
Land and on Marine Fixed and Mobile Platforms, Second Edition, with
Supplement. API RP 500 combined API RP 500A, 500B, and 500C into a
single document to provide guidelines for classifying locations at
petroleum facilities for the selection and installation of electrical
equipment. API RP 500 contains essentially the same information
contained in API RP 500B. API RP 500 is referenced in Sec. 250.51(i) to
classify fuel and other flammable liquid storage locations. Also,
references to API RP 500 replace API RP 500B in Secs. 250.53(b),
250.122(e)(4)(i), 250.123(b)(9)(i), 250.291(b)(3) and (d)(4)(i), and
250.292(b)(4)(i).
2. Add a new Sec. 250.27, Safety of operations communication, that
requires operators of offshore production platforms to notify incoming
or new personnel arriving on the platform of the status of repairs of
process equipment, safety systems, or other systems that are out of
service. The new regulation also requires operators to maintain records
of all communications.
3. Revise Sec. 250.51, General requirements, to include
requirements for fuel storage on offshore facilities.
4. Revise Sec. 250.123, Additional production system requirements,
to be more specific on identifying and deactivating process equipment
and controls when safety systems are out of service and maintaining
records.
5. Add a new paragraph, Sec. 250.153(a)(5), that requires operators
to protect horizontal sections of pipeline risers from damage by
falling objects.
6. Revise Sec. 250.154 to require pipeline shutdown valves to be
located below the lowest production deck on all new pipelines entering
and departing OCS platforms. This rule also applies to all pipelines
under the jurisdiction of MMS, including production flow lines,
gathering lines, sulphur pipelines, fuel lines, bidirectional lines,
and crossing pipelines. For existing platforms and pipelines, the rule
requires installation or relocation of valves when significant riser
repairs or maintenance is performed.
7. Revise Sec. 250.158 to give the Regional Supervisor authority to
require operators to submit written pipeline repair procedures for
approval. The preparation and approval of written plans ensure that an
operator adequately considers the repair activity.
Author
The principal authors of this proposed rule are Elmer P.
Danenberger, Chief, Engineering and Technology Division, and Paul
Schneider, Technology Assessment and Research Branch.
Regulatory Flexibility Act
The DOI has also determined that this proposed rule will not have a
significant economic effect on a substantial number of small entities
because, in general, the entities that engage in activities offshore
are not considered small due to the technical complexities and level of
financial resources necessary to safely conduct such activities.
Paperwork Reduction Act
This proposed rule adds new information collection requirements to
subparts A and J. The information collection requirements contained in
this rule have been submitted to the Office of Management and Budget
(OMB) for approval as required by the Paperwork Reduction Act (44
U.S.C. 3501 et seq.). The collection of this information will not be
required until it has been approved by OMB. Public reporting burdens
for the new information collection requirements contained in subparts A
and J are estimated to average 8 hours per response, including the time
for reviewing instructions, searching existing data sources, gathering
and maintaining the data needed, and completing and reviewing the
collection of information. Send comments regarding these burden
estimates or any other aspects of this collection of information,
including suggestions for reducing the burden, to the Information
Collection Clearance Officer; Minerals Management Service; Mail Stop
2053, 381 Elden Street; Herndon, Virginia 22070-4817, and the Office of
Management and Budget; Paperwork Reduction Project (1010-0030) for
subpart A and (1010-0050) for subpart J; Washington, DC 20503,
telephone (202) 395-7340.
Takings Implication Assessment
The DOI certifies that the proposed rule does not represent a
governmental action capable of interference with constitutionally
protected property rights. Thus, a Takings Implication Assessment need
not be prepared pursuant to E.O. 12630, Government Action and
Interference with Constitutionally Protection Property Rights.
E.O. 12778
The DOI has certified to OMB that this proposed regulation meets
the applicable civil justice reform standards provided in sections 2(a)
and 2(b)(2) of E.O. 12778.
National Environmental Policy Act
The DOI has determined that this action does not constitute a major
Federal action significantly affecting the quality of the human
environment; therefore, preparation of an Environmental Impact
Statement is not required.
E.O. 12866
This rule was reviewed under E.O. 12866. The rule was determined to
not be a significant rule under the criteria of E.O. 12866 and,
therefore, was not reviewed by OMB.
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: April 4, 1994.
Bob Armstrong,
Assistant Secretary, Land and Minerals Management.
For the reasons set forth in the preamble, 30 CFR part 250 is
proposed to be amended 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: Sec. 204, Pub. L. 95-372, 92 Stat. 629 (43 U.S.C.
1334).
2. In Sec. 250.1, paragraphs (d)(9) and (d)(15) are revised as
follows:
Sec. 250.1 Documents incorporated by reference.
* * * * *
(d) * * *
(9) API RP 14C, Recommended Practice for Analysis, Design,
Installation and Testing of Basic Surface Safety Systems for
Offshore Production Platforms, Fourth Edition, September 1, 1986,
API Stock No. 811-07180, incorporated by reference at
Secs. 250.51(i); 250.122 (b) and (e)(2); 250.123(a), (b)(2)(i),
(b)(4), (b)(5)(i), (b)(7), (b)(9)(v), and (c)(2); 250.124 (a) and
(a)(5); 250.152(d); 250.154(b)(12); 250.291 (c) and (d)(2); 250.292
(b)(2) and (b)(4)(v); and 250.293(a).
* * * * *
(15) API RP 500, Recommended Practice for Classification of
Locations for Electrical Installations at Petroleum Facilities,
First Edition, June 1, 1991, API Stock No. 811-06005, incorporated
by reference at Secs. 250.51(i), 250.53(b), 250.122(e)(4)(i),
250.123(b)(9)(i), 250.291(b)(3) and (d)(4)(i), and 250.292(b)(4)(i).
* * * * *
3. A new Sec. 250.27 is added to subpart A to read as follows:
Sec. 250.27 Safety of operations communication.
At the beginning of each crew shift and upon addition or
replacement of personnel, incoming workers shall receive safety
information relative to activities and repairs underway on the facility
and any process or safety equipment that is out of service. This
information may be provided through a safety meeting, a notice provided
to each employee, or a posted notice that must be read by each
employee. A record of this communication shall be kept and maintained
at the facility.
4. In Sec. 250.51, a new paragraph (i) is added to read as follows:
Sec. 250.51 General requirements.
* * * * *
(i) Diesel and other fuel storage tanks, drums containing
lubricants, cleaners, and other flammable liquids shall be clearly
labeled and located as far as practicable from ignition sources.
Storage locations shall be classified in accordance with the American
Petroleum Institute (API) Recommended Practice (RP) for Classification
of Locations for Electrical Installations at Petroleum Facilities (API
RP 500). Tanks shall be adequately vented or equipped in accordance
with API RP for Analysis, Design, Installation and Testing of Basic
Surface Safety Systems for Offshore Production Platforms (API RP 14C).
Fire detection devices, such as fusible plugs, shall be installed in
fuel and flammable liquid storage areas.
5. In Sec. 250.53, paragraph (b) is revised to read as follows:
Sec. 250.53 Electrical equipment.
* * * * *
(b) All areas shall be classified in accordance with API RP 500,
Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities.
* * * * *
6. In Sec. 250.122, the introductory text of paragraph (e)(4)(i) is
revised to read as follows:
Sec. 250.122 Design, installation, and operation of surface
production-safety systems.
* * * * *
(e) * * *
(4) * * *
(i) A plan of each platform deck outlining all hazardous areas
classified in accordance with API RP 500, Recommended Practice for
Classification of Location for Electrical Installations at Petroleum
Facilities, and outlining areas in which potential ignition sources,
other than electrical, are to be installed. The area outline shall
include the following information.
* * * * *
7. In Sec. 250.123, paragraphs (b)(9)(i) and (c)(1) are revised to
read as follows:
Sec. 250.123 Additional production system requirements.
* * * * *
(b) * * *
(9) Fire- and gas-detection system. (i) Fire (flame, heat, or
smoke) sensors shall be installed in all enclosed classified areas. Gas
sensors shall be installed in all inadequately ventilated, enclosed
classified areas. Adequate ventilation is defined as ventilation that
is sufficient to prevent accumulation of significant quantities of
vapor-air mixture in concentrations over 25 percent of the lower
explosive limit (LEL). One approved method of providing adequate
ventilation is a change of air volume every 5 minutes or 1 cubic foot
of air-volume flow per minute per square foot of solid floor area,
whichever is greater. Enclosed areas (e.g., buildings, living quarters,
or doghouses) are defined as those areas confined on more than four of
their six possible sides by walls, floors, or ceilings more restrictive
to air flow than grating or fixed open louvers and of sufficient size
to allow entry of personnel. A classified area is any area classified
Class I, Group D, Division 1 or 2, following the guidelines of API RP
500.
* * * * *
(c) General platform operations. (1) Surface or subsurface safety
devices shall not be bypassed or blocked out of service unless they are
temporarily out of service for startup, maintenance, or testing
procedures. Personnel shall monitor the bypassed or blocked-out
functions until the safety devices are placed back in service. Any
surface or subsurface safety device that is temporarily placed out of
service shall be flagged. When conducting repairs or maintenance that
expose the production safety system to the atmosphere or to conditions
that constitute a potential danger to safety of personnel or protection
of the environment, the system shall be purged of hydrocarbons and flow
shall be blocked from the area under repair or maintenance. Valves,
pumps, or other equipment that could initiate flow through the
designated area shall also be flagged and removed from service. The
activation of such equipment from the control panel shall be
temporarily precluded. Only the person in charge of the repair or
maintenance may authorize the resumption of service. This authorization
may not be given until the repair or maintenance action is completed.
* * * * *
8. In Sec. 250.153, a new paragraph (a)(5) is added to read as
follows:
Sec. 250.153 Installation, testing, and repair requirements for DOI
pipelines.
(a) * * *
(5) Risers shall be designed to prevent damage from falling debris.
Horizontal sections of risers shall be of minimal length and protected
to prevent damage from falling objects.
* * * * *
9. In Sec. 250.154, paragraphs (b) and (c) are revised to read as
follows:
Sec. 250.154 Safety equipment requirements for DOI pipelines.
* * * * *
(b) All new oil, gas, or sulphur pipelines approved or modified
after the effective date of these regulations shall comply with this
section, where applicable.
(1)(i) Incoming pipelines to a platform shall be equipped with a
flow safety valve (FSV).
(ii) For sulphur operations, incoming pipelines delivering gas to
the power plant platform may be equipped with high- and low-pressure
sensors (PSHL), which activate audible and visual alarms in lieu of
requirements in paragraph (b)(1)(i) of this section. The PSHL shall be
set at 15 percent or 5 psi, whichever is greater, above and below the
normal operating pressure range.
(2) Incoming pipelines boarding to a production platform or
delivering gas to a power plant platform shall be equipped with an
automatic shutdown valve (SDV) below the lowest production deck of the
platform. The SDV shall be connected to the automatic- and remote-
emergency shut-in systems.
(3) Departing pipelines receiving production from production
platforms shall be protected by PSHL to directly or indirectly shut in
all production facilities. The PSHL shall be set not to exceed 15
percent above and below the normal operating pressure range. However,
high pilots shall not be set above the pipeline's maximum allowable
operating pressure.
(4) Departing pipelines from a production platform shall be
equipped with an SDV below the lowest production deck of the platform.
The SDV shall be connected to the automatic- and remote-emergency shut-
in systems in a manner that allows the safe shut in of the platform
prior to SDV closure.
(5)(i) Crossing pipelines on production or manned nonproduction
platforms shall be equipped with an SDV on both the incoming and
departing lines below the lowest production deck. These SDVs shall be
connected to the automatic- and remote-emergency shut-in systems.
(ii) Crossing pipelines on unmanned nonproduction platforms shall
be equipped with an FSV.
(6) Bidirectional pipelines servicing production or manned
nonproduction platforms shall be equipped with a PSHL and an SDV on all
risers.
(7) All SDV's shall be operable locally and connected to the
automatic- and remote-emergency shut-in systems. The SDV shall be
protected from fire, explosion, and impacts from falling objects and
marine vessels. The SDV shall be accessible for inspections,
maintenance, repairs, and testing. The SDV shall be inspected and
tested at least once each calendar month, but the interval shall not
exceed 6 weeks.
(8) For facilities and pipelines installed prior to the effective
date of these regulations, an SDV shall be installed when riser
maintenance or repair is performed.
(9) The Regional Supervisor may require that oil pipelines be
equipped with a metering system to provide a continuous volumetric
comparison between the input to the line at the structure(s) and the
deliveries onshore. The system shall include an alarm system and shall
be of adequate sensitivity to detect variations between input and
discharge volumes. In lieu of the foregoing, a system capable of
detecting leaks in the pipeline may be substituted with the approval of
the Regional Supervisor.
(10) Pipelines incoming to a subsea tie-in shall be equipped with a
block valve and a FSV. Bidirectional pipelines connected to a subsea
tie-in shall be equipped with only a block valve.
(11) Gas-lift or water-injection pipelines on unmanned platforms
need only be equipped with an FSV installed immediately upstream of
each casing annulus or the first inlet valve on the wellhead.
(12) Pipeline pumps shall comply with Section A7 of API RP 14C. The
setting levels for the PSHL devices are specified in paragraph (b)(5)
of this section.
(c)(1) If the SDV or other required safety equipment is rendered
ineffective or removed from service on pipelines that are continued in
operation, an equivalent degree of safety shall be provided. The
affected safety equipment shall be identified by the placement of a
sign on the equipment stating that the equipment is rendered
ineffective or removed from service.
(2) When conducting repairs or maintenance to the pipeline system
components that expose the pipeline to the atmosphere or to conditions
that constitute a potential danger to safety of personnel or protection
to the environment, the system shall be purged of hydrocarbons and flow
shall be blocked from the area under repair or maintenance. Valves,
pumps, or other equipment that could allow or initiate flow through the
designated area shall also be flagged and removed from service.
Activation of this equipment from the control panel shall be
temporarily precluded. Only the person in charge of the repair or
maintenance may authorize the resumption of service. This authorization
may not be given until the repair or maintenance action is completed.
10. In Sec. 250.158, paragraph (e) is revised to read as follows:
Sec. 250.158 Reports.
* * * * *
(e)(1) Except for emergency repairs necessary to prevent or
minimize pollution or the loss of human life, the lessee or right-of-
way holder shall notify the Regional Supervisor prior to the repair of
any pipeline or pipeline component. Based on the nature of the repair,
the Regional Supervisor may require the lessee or right-of-way holder
to submit detailed pipeline repair procedures for approval before
conducting repairs. The repair procedures shall include the types of
equipment and specifications of components used in the repair.
(2) A detailed report of the pipeline repair shall be submitted to
the Regional Supervisor within 30 days after completion of the repair.
The report shall include the following:
(i) Type of damage sustained and cause:
(ii) Type and volume of hydrocarbons lost due to damage;
(iii) Specifications of components utilized in the repair and a
detailed repair procedure;
(iv) Results of pressure and other verification tests; and
(v) Date pipeline or component returned to service.
* * * * *
11. In Sec. 250.291, paragraphs (b)(3) and (d)(4)(i) are revised to
read as follows:
Sec. 250.291 Design, installation, and operation of production
systems.
* * * * *
(b) * * *
(3) Electrical system information, including a plan of each
platform deck that shows:
(i) All hazardous areas classified in accordance with API RP 500,
Recommended Practice for Classification of Locations for Electrical
Installations at Petroleum Facilities; and
(ii) All areas in which potential ignition sources are to be
installed;
* * * * *
(d) * * *
(4) * * *
(i) A plan of each platform deck, outlining all hazardous areas
classified in accordance with API RP 500 and outlining areas in which
potential ignition sources are to be installed;
* * * * *
12. In Sec. 250.292, paragraph (b)(4)(i) is revised to read as
follows:
Sec. 250.292 Additional production and fuel gas system requirements.
* * * * *
(b) * * *
(4) Fire- and gas-detection system. (i) Fire (flame, heat, or
smoke) sensors shall be installed in all enclosed classified areas. Gas
sensors shall be installed in all inadequately ventilated, enclosed
classified areas. Adequate ventilation is defined as ventilation that
is sufficient to prevent accumulation of significant quantities of
vapor-air mixture in concentrations over 25 percent of the LEL. One
approved method of providing adequate ventilation is a change of air
volume every 5 minutes or 1 cubic foot of air-volume flow per minute
per square foot of solid floor area, whichever is greater. Enclosed
areas (e.g., buildings, living quarters, or doghouses) are defined as
those areas confined on more than four of their six possible sides by
walls, floors, or ceilings more restrictive to air flow than grating or
fixed open louvers and of sufficient size to allow entry of personnel.
A classified area is any area classified Class I, Group D, Division 1
or 2, following the guidelines of API RP 500.
* * * * *
[FR Doc. 94-11601 Filed 5-13-94; 8:45 am]
BILLING CODE 4310-MR-M
