Improving the Safety of Marine Pipelines (1994) / Chapter Skim
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4 Maintaining the Integrity of the Marine Pipeline Network
4 Maintaining the Integrity of the Marine Pipeline Network
Pages 45-65
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From page 45... ...
rlpelllles in slule walers are even older, with some dating from the early l950s, when offshore pipeline construction began. Coatings, cathodic corrosion protection, and internal corrosion monitoring have improved substantially since then.
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From page 46... ...
pipelines are less prescriptive, setting only general performance standards for internal and external corrosion control; in practice, however, corrosion protection practices are similar to those used for gas pipelines. MMS permits require operators to meet OPS design standards for corrosion prevention (30 CFR 250.152~; the agency also maintains a data base of cathodic corrosion protection systems, so that operators can be notified when the systems need inspection.
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From page 47... ...
New systems to record corrosion control data using ROVs have not yet achieved widespread use, but are increasingly accepted by the pipeline industry (Weldon and Kroon, 1992~. Conventional cathodic protection monitoring of offshore pipelines is generally conducted by measuring the pipe-to-electrolyte potential of the pipeline at easily accessible points, generally the platform riser and/or a point onshore.
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From page 48... ...
In both gas and liquid lines, corrosive mixtures of foreign materials such as brine, drilling fluids, and bacteria from production reservoirs, not removed by production equipment, travel in the product stream. Metal loss from internal corrosion is generally concentrated at the bottoms of the pipe and at low spots, especially in gas lines because the corrosive substances tend to be heavier than oil or gas.
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From page 49... ...
Research is underway by the pipeline industry to reduce the length and weight and improve the accuracy of such devices. Internal corrosion tends to occur fairly consistently in several distinct locations of offshore pipelines: in the bends at the bases of risers (pipes that connect seabed pipelines to platforms)
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From page 50... ...
devices (generally known as smart pigs) passed through the line to record data that indicates metal loss or certain other pipe characteristics.
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From page 51... ...
The question of cost-effectiveness, though, will remain a real one. Even with marine pipelines that can accommodate smart pigs, the procedure is significantly less cost-effective offshore than onshore: · The consequences of the corrosion failures and other minor leaks that could be prevented by smart pigs are smaller offshore, with no human safety or property damage impacts and generally minimal environmental impacts (see Chapter 24.
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From page 52... ...
It concluded that using smart pigs is cost-effective when only minor modifications to the existing pipeline are needed to accommodate them, and when one or more specific risk factors is present, such as proximity to a highly populated area, known corrosion or coating disbanding, or pipe deformation due to settlement or dredging activity. The cost-benefit analysis considered the safety, property damage, and environmental consequences of pipeline leaks as well as the costs of the periodic surveys.
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From page 53... ...
In addition, smart pigs need to be further developed in their ability to detect other pipe defects, such as metal loss in weld zones and disbanded coatings. The GAO report recommended that, as the Office of Pipeline Safety completes its studies and rulemaking on the use of smart pigs, it consider the capabilities, limitations, and costs of smart pig surveys.
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From page 54... ...
In the case of flow lines, the use of smart pigs is precluded, because of their small diameters and the lack of means to install pig launch traps. For risers, inspections by divers or ROVs carrying ultrasonic thickness devices, or specially equipped tethered smart airs can be used for these local in~nection.~ Fv~.n in those cases, the emphasis is on corrosion prevention and corrosion control monitoring metal loss is suspected only when identifiable risk factors exist.
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From page 55... ...
Pipelines taken out of service for repair must be pressure-tested before being returned to service, and pressuretesting may be required if the Regional Supervisor has reason to believe the pipeline has been damaged or weakened (30 CFR 250.155~. Only in California, on the outer continental shelf, is the use of smart pigs routinely required by regulators of the Minerals Management Service; there, the pipelines are more recently installed, for the most part, with fewer connections and elbows to impede the passage of pigs.
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From page 56... ...
Marine transmission pipelines function more like gathering systems than like traditional point-to-point transmission lines on shore (Darwin, 1992~. That is, they collect product from various production platforms and transport them to shore facilities for further transmission to refineries or distribution.
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From page 57... ...
These observations, generally made during routine traffic of personnel and supplies, have been an important means of leak detection and have worked well, according to MMS personnel (personal communication, Alexander Alvarado, Minerals Management Service Gulf of Mexico Region, March 11, 1994~. Aircraft and vessel operators sighting a leak or spill are required to report the sighting.
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From page 58... ...
Setpoint-limit control systems establish limits on operating parameters such as pressures or flow rates, or (much less frequently) the rate at which they change, to identify upset conditions.
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From page 59... ...
\ . \/ -' runt Limit Control Leak Size 59 FIGURE 4-2 Schematic drawing comparing the advantages of different leak detection methods as functions of sizes of leaks and detection times.
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From page 60... ...
Emergency shutdown systems, flow restricting check valves, and pipeline isolating block valves minimize or prevent leaks, and emergency response procedures and
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From page 61... ...
Emergency Shutdown and Platform Isolation Systems Emergency shutdown systems on transmission pipelines include high- and low-pressure switches or automatic pilots and, where metering exists, high flow switches at the originating points. Additionally, an emergency shutdown capability exists locally on the platform and, in some cases, remotely from a central control center.
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From page 62... ...
This determination is based upon, among other things, both the potential adverse and beneficial impacts valve closures and other operator actions could have on the safety of the pipeline system and other connecting laterals and platforms. The OPS, under the Pipeline Safety Act of 1992, must issue regulations prescribing the circumstances in which operators of hazardous liquid pipelines must use emergency flow-restricting devices and other .sv~tewc or nror:~.~1llre.~ try r1P.tPrt Singling r',nt~lr-a ~nr]
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From page 63... ...
In many cases, the pipeline operator will not have the instantaneous capability of shutting down the facilities injecting into the pipeline system or of isolating the leaking segment (Alvarado et al., 1991; Howard et al., 1991; National Transportation Safety Board, 1990~. Production facilities that inject into pipelines must be shut down in a properly sequenced fashion to preclude the development of pressure surges or other unsafe consequences on injecting production platforms.
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From page 64... ...
Operators use a variety of complementary monitoring and control techniques to limit corrosion. Smart pigs have great promise, but most offshore pipelines are not physically or operationally suited to their use.
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From page 65... ...
1992. Natural Gas Pipelines: Greater Use of Instrumented Inspection Technology Can Improve Safety.
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