[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] ======================================================================= ----------------------------------------------------------------------- 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. ----------------------------------------------------------------------- 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