Safety Requirements Governing Production Platforms and Pipelines

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