Abstract This paper presents the work performed by Conoco Indonesia Inc. in developing and testing a unique re-entry system for wireline work on two seafloor wells in 295 feet of water at Kepiting Field in the Natuna Sea of Indonesia. This system does not require the use of a floating drillship for conventional wireline work in a seafloor well. The main components are: A 240 foot buoyantly tensioned stool seafloor riser A surface buoy which connects temporarily to the seafloor riser and also supports an above water work platform for the wireline lubricator assembly A set of strategically located permanent workboat moorings A workboat arranged to serve as the wireline unit's operating platform and to provide all support services. This paper discusses the components, installation and performance of this unique wireline re-entry system. Introduction The Kepiting Field is located about 5 miles Southwest of Conoco's Udang Field. (See Figure 1). The area is out of the typhoon track and has a relatively mild environmental regime. The 100 year wave is 38 feet (hs=19 feet). The Kepiting reservoir was discovered in June, 1982 at a depth of 5900 feet. The oil sand has 43 feet of not pay and tested at rates of 5240 and 6010 BOPD in two separate zones. Not withstanding the mild weather system and encouraging reservoir test results, there were three prominent obstacles to economic production: Water depth is 295 feet Mapped recoverable reserves are insufficient to economically support the investment in a platform based drilling and production system Crude oil has a 100 Fahrenheit pourpoint and carries erosive sand DEVELOPMENT STUDIES Studies of various alternative development schemes were evaluated. These included subsea completions tied back to a Floating Production Storage and Offloading vessel (FPSO), a steel piled wellhead tripod with an FPSO tethered to the same, or a limited production facilities platform with an FPSO anchored on a single point mooring. Because the small reserves dictated minimum capital investment, it was found that the seafloor development with an FPSO was the most economically attractive. The subsea system uses multiple seafloor trees linked to the FPSO by flexible risers which provide well control, production flowline and gas lift flowline. This system was developed and is currently operating two seafloor wells at the Kepiting Field. In the studies of the above mentioned development schemes, it was recognized that inexpensive well maintenance was needed for efficient reservoir management and would present a challenge to the field developers. A review of existing subsea systems disclosed that none had successfully and inexpensively solved the problem of wireline re-entry using conventional equipment and techniques in this waterdepth. Artificial lift was required and the two zones at Kepiting needed to be produced independently, either through dual completions, or by using multizone-single selective completions similar to those used to produce the reserves in the nearby Udang Field. Multizone-single selective seafloor completions, equipped with gas lift valves for artificial lifting, were selected for Kepiting wells. Figure 2 illustrates the downhole equipment arrangement and indicates the various downhole operations required to produce such wells. Wireline works include: Pulling and checking the subsurface safety valve. Setting a plug to close the lower zone and opening a side door sleeve to the upper zone.. Changing out gaslift valves.. Bailing sand, if needed. An estimated minimum of 3 wireline re-entries are required during the well life. Several more trips may be required if problems develop with the safety valve or gaslift valves. For the two well completion at Kepiting, this amounts to a minimum of 6 wireline operations. P. 304^

Abstract The paper deals with the handling of liquids in the multi-phase flow pipeline system within Carigali's Duyong Offshore Gas Complex and the Onshore Gas Terminal, in Kerteh, Terengganu. The data and operations experience gathered necessitate changes to the operating procedures originally identified during the design phase. This is to ensure more efficient handling of liquid hold-up in the pipeline during low gas flowrates. Introduction The gas Gathering System, situated at both offshore Terengganu, in the east coast of peninsular Malaysia, comprises the following installations: Duyong Gas Field Complex Sotong Collector Platform (SCP) Onshore Gas Terminal (OGT) The Duyong Gas Field Complex, situated 200 km offshore, in water depths ranging from 70 to 80 meters, comprises the following platforms: Wellhead Platform A (WPA) Wellhead Platform B (WPB) Wellhead Platform C (WPC) Central Processing Platform (CPP) Living Quarters Platform (LQP) The flow scheme of the entire system is shown in Figure 1. The detailed description of these facilities is described in the next section. The Duyong Gas Field and the OGT have been operated below the designed production rates, for a period of approximately three years, due to low gas demand by the consumers. The average gas production from the Duyong Field is approximately 0.85 X 10-6 Sm3/day, ranging from a minimum of 0.29 × 10-6 Sm3/day to a maximum of 1.40 × 10-6 Sm3/day. The Duyong gas production contributes approximately 50 percent of the total gas delivered to the OGT. The remaining 50 percent comes from EPMI's field through the SCP. Production from Duyong is maintained on a rotational basis, from one single wellhead platform at any one time. This is done to monitor the performance of all the wells and the associated facilities on the CPP, and to cater for the low gas demand. Each wellhead platform is allowed to produce continuously for a period of two months. The low gas flowrate resulted in larger liquid hold-up in the Duyong pipeline system. Handling of liquid hold-up on the CPP during pigging operations, in the early days, had been a major concern to Carigali since it had caused several shutdowns of the offshore facilities. Initially, handling condensate at the OGT had resulted in discontinuation of gas supply, for short durations, to the Gas Processing Plant (GPP) operated by PETRONAS Gas Sdn. Bhd. (PGSB). The above mentioned liquid handling problems, however, were overcome by revising the designed operating procedures. DESCRIPTION OF FACILITIES Each wellhead platform is designed to produce 2.80 × 10-6 Sm3/day of gas and 330 Sm3/day of liquid. The produced fluids, comprising gas, condensate and produced water from WPA and WPC are routed to the CPP via two separate 5.6 km and 5-km 14-inch multiphase subseas pipelines respectively. The production from WPB is routed to CPP via a 10-inch production flowline alongside a 30 meter bridge connecting the two platforms. The CPP, which forms the central hub of the Duyong Gas Field Complex, is designed to receive and treat 7.0 X 10-6 Sm3/day of gas and 1250 Sm3/day of condensate from the wellhead platforms. Three production trains on the CPP ensure continuous production to the OGT. P. 876^

Salleh, Hashim, Petronas Gas Sendirian Berhad, Malaysia Petronas Gas Sendirian Berhad, Malaysia This paper was prepared for presentation at the Offshore South East Asia Conference and Exhibition held in Singapore, January 28-31, 1986. The Conference was sponsored by SPE, SEAPEX and SNAME. Abstract The paper will discuss the philosophy and strategy in the implementation of the first stage of the Malaysian Peninsular Gas Utilisation Project. The focus will be on project management, technology transfer, local participation and the lessons from the experience. The project is implemented in three stages. Stage I, which involves the processing and delivery of gas within Terengganu is processing and delivery of gas within Terengganu is now completed. Stage II, which involves the piping of gas to the power stations in Port Kelang and Port Dickson and southward to Singapore is under initial implementation. Stage III, delivery to the north, will be implemented later. Introduction Currently, Malaysia's total energy consumption is estimated to be equivalent to some 222,000 barrels of oil per day. it is expected that with industrialisation, Malaysia's energy consumption will increase and this is projected to grow at a rate of 5 - 7% annually for the period 1985 - 2000. Oil is currently meeting about 82.4% of this consumption with hydropower, a poor second, meeting about 7.7%. Malaysia therefore is fortunate to have its own indigenous oil reserves as an energy source and a foreign exchange earner. However, Malaysia's known recoverable reserves of oil are comparatively small. Our oil reserves are currently estimated at 3.1 billion barrels. At the present rate of production of about 420,000 barrels per day, our reserves will be depleted within 20 years assuming no new oil fields are discovered and that the existing level of oil recovery technology remains the same. Not withstanding that fact, Malaysia's favourable status as a net exporter of oil could be reversed in the not too distant future. Fortunately, Malaysia is endowed with comparatively large reserves of natural gas. Our recoverable reserves are estimated at 53 trillion cubic feet (TCF) comprising 43 TCF of non-associated gas and 10 TCF of associated gas. On an energy equivalent basis, the 53 TCF of gas amount to some 9 billion barrels of oil equivalent or almost three times Malaysia's oil reserves. It should be noted that although our predominant energy reserves is natural gas, we are still highly dependent on oil in spite of the fact that our domestic prices of oil products, particularly gasoline and LPG, are higher than the most expensive price of gas in the form of LNG. It is, therefore, price of gas in the form of LNG. It is, therefore, in Malaysia's interest to substitute oil with natural gas in order to Diversify the sources of primary energy supply based on available indigenous resources; Replace imported fuel oil for power generation and hence save on foreign exchange; Provide a stable supply of fuel and feedstock for industries; Produce by-products such as LPG (i.e., liquefied Petroleum Gas) and condensates, most of which can be exported for foreign exchange earnings; and Increase foreign exchange earnings through the export of surplus gas resources, Recognising the potential importance of natural gas to the nation, PETRONAS initiated the Peninsular Gas Utilisation Project (PGU) in 1982. This move was also recommended in the Gas Utilisation Masterplan Report prepared by Chem System Inc, an international consultancy engaged by PETRONAS. PENINSULAR GAS UTILISATION PROJECT PENINSULAR GAS UTILISATION PROJECT The Peninsular Gas Utilisation Project is being implemented in three stages Stage I This Stage involved the construction of a plant to process gas from offshore Terengganu and the laying process gas from offshore Terengganu and the laying of a pipeline system for distribution of the processed gas to the LLN Power Station at Paka, the processed gas to the LLN Power Station at Paka, the PERWAJA Steel Mill at Telok Kalong and a pilot gas PERWAJA Steel Mill at Telok Kalong and a pilot gas reticulation project at Kerteh, Stage I also included the construction of am LPG Export Terminal at Tanjong Sulong in the Kemaman district Stage I has already been completed and I shall elaborate on the implementation aspects shortly. Stage II This provides for additional capacity to the Gas Processing Plant and the laying of a pipeline system Processing Plant and the laying of a pipeline system to transport gas from Terengganu to power stations and industries along the West Coast and down south to Johore Bahru and also for sale to Singapore. This stage is currently under implementation. Stage III At this stage, the trans-peninsular pipeline will be extended from the Klang Valley to the Prai Power Station in the north. This stage is still under planning. planning. IMPLEMENTATION OF STAGE I Stage I of the PGU-Project was the first gas project undertaken by PETRONAS in Peninsular project undertaken by PETRONAS in Peninsular Malaysia and required a range of multi-disciplinary expertise. At the time of implementation, neither PETRONAS nor the local companies had the experience or expertise to undertake a project of this nature and magnitude. Therefore, it was deemed necessary to engage foreign expertise for the design, management and construction of the project. Nevertheless, to allow for some local participation in implementing the project, the turnkey concept was adopted, with the resulting three-tier hierachical arrangement: Owner - who would be responsible for feasibility studies, coordinating with other parties, (eg. gas sellers and consumers) and for physical and financial control of the project; Consultant - who would be responsible for basic design and overall project management; and Contractor - who would be responsible for detailed engineering, procurement and construction. In this context, the "owner" of the project is PETRONAS Gas Sdn Bhd or PGSB for short, which was PETRONAS Gas Sdn Bhd or PGSB for short, which was established by PETRONAS in 1983 as a wholly-owned subsidiary to implement the project.

Bomba, John G., R J Brown and Associates (Far East) Pte Ltd Abstract Pipeline transport of waxy crude oils can be performed effectively, both from technical and performed effectively, both from technical and economic standpoints, through adequate system designs. Such pipeline designs must consider safety aspects, system integrity, ease of installation, and potential operating and maintenance problems. potential operating and maintenance problems. General topics which must be reviewed will include features of the waxy crudes, fluid heating and temperature loss control potential, factors influencing and methods of controlling wax accretions, and problems involved with shutdown and startup. A general review of pump effectiveness for waxy crude transport is provided. A cost comparison of pipeline transport with other methods of waxy crude movement, such as barge tow or tanker handling, is presented. This paper is essentially a review of waxy crude oils and their features related to offshore transport. It will serve as an information source for engineers who are inexperienced in dealing with waxy crudes and as a guideline and source of ideas for more experienced engineers that must design transport facilities. Effectively designed pipeline systems can be established to handle waxy rude oil transport. In most cases, pipelines are a cost effective method of transport when compared to other alternates such as barge or tanker shipment. Introduction There is nothing really new about transportation of waxy crudes by pipeline, even offshore. The industry has been doing it for years, sometimes successfully, sometimes not so, sometimes with drastic or catastrophic consequences. While this paper will probably not contain anything new, the contents are directed toward eliminating catastrophic failures and avoiding, in so far as is economically possible for a particular set of project circumstances, not so successful operations. The design process for an offshore pipeline is not much different from one onshore. The ocean is an infinite heat sink - this must be taken into account. Insulated pipelines usually require addition of weight to provide stability against hydrodynamic forces. Expansion problems are usually more severe offshore. Start-up problems exist. Unscheduled cool downs can be extremely serious. Produced water and gas can cause problems. No one Produced water and gas can cause problems. No one knows very much about two phase flow of oil-water emulsions and liberated gas. (This does occur!) With all these potential problems, how does one design an offshore waxy crude pipeline system? There are several ways, with the extremes being literally "Brute Force and Awkwardness" and "like a Nuclear Reactor Cooling System", and a middle-of-the-road, sound engineering approach, which this paper will try to present. DEFINITION OF A WAXY CRUDE A waxy crude is defined as a crude oil having a high pour point and low API gravity, and often containing paraffin wax (alkanes). A waxy crude is distinguished by the fact that it exhibits non-Newtonian viscosity behaviour at temperatures below about 20F above the pour point. This means that the effective viscosity below this value is not a function of temperature alone, but is also a function of the effective rate of shear in the pipeline. Shear stress and rate of shear must be pipeline. Shear stress and rate of shear must be determined to predict the pressure required to deliver a specified production volume. A waxy crude may exhibit Bingham plastic characteristics after gelling. The behaviour of this type of waxy crude varies from that of Newtonian fluids only in that a specified yield stress must be exceeded to initiate flow. The viscosity of a Bingham plastic is rate of shear and time dependent. For a laminar flow condition, the effective viscosity of the fluid depends on the uniform rate of shear, which is a function of the flow rate and pipe inside diameter. When the flow is turbulent, pipe inside diameter. When the flow is turbulent, there is a thin boundary layer adjacent to the pipe wall which is subjected to a rate of shear pipe wall which is subjected to a rate of shear under laminar conditions. Oil in thins boundary layer becomes rapidly mixed with the bulk of the oil in the centre of the pipe. It is this high rate of shear in the boundary layer which is the appropriate rate of shear for determining effective viscosity. Generally, this is obtained by multiplying the uniform rate of shear (laminar flow condition) by a correct ion factor depending only on the Reynolds number. If a waxy crude is allowed to cool below its pour point under static conditions in a pipeline (no flow point under static conditions in a pipeline (no flow in the pipeline), the wax will crystallize, causing the entire mass of crude oil to gel. Because of this gelling effect upon cool-down, the initial concept is to operate the pipeline at temperatures above the crude's pour point. However, there is no particular problem in transporting the waxy crude particular problem in transporting the waxy crude below its pour point, provided the fluid is kept in motion. More pressure is required for the fluid in non-Newtonian range, although there is no sudden change in fluid characteristics at the pour point. When a waxy crude pipeline operating below the crude's pour point is shut down for any reason, the resulting gel led state will require, upon restart, substantially more pressure to put it in motion. However, this additional restart pressure will be substantially less than if the pipeline was operating above the crude's pour point, shut down and then allowed to cool down statically. The most important criterion in designing pipelines transporting waxy crude is whether the line can be restarted easily after a shut down. PRACTICAL ASPECTS OF PIPELINE TRANSPORT PRACTICAL ASPECTS OF PIPELINE TRANSPORT We have identified the basic physical problems and some of the rheologic characteristics of waxy crudes which affect pipelining. The obvious solutions to these problems are: – Do not let wax deposit out – Keep the crude oil hot – Keep it moving Factors Affecting Wax Deposition Temperature The primary factor affecting wax deposition in the pipelines is temperature. As the temperature of the pipelines is temperature. As the temperature of the produced fluid falls below the melting point of the produced fluid falls below the melting point of the wax, it tends to solidify and separate from the liquid phase. This is followed by the wax crystals bonding together to form larger masses (cohesion), and subsequent sticking of these masses to the equipment/pipelines (adhesion). The hardest waxes, those with the highest melting point, will deposit first at higher temperatures, probably in the production string of the well. The softer waxes production string of the well. The softer waxes will come out in the cooler portions of the surface equipment and transporting pipelines.

Abstract An application of a computer system is investigated for the purpose of the assistance in the operation of a semi-submersible drilling unit. A conceptional design of application softwares and a configuration of hardwares are studied. The required major functions, flow chart, input data and output data are presented for each program. presented for each program. The system seems effective for the calculations of loading, stability, mooring and riser analysis. PREFACE PREFACE Although the world faced recessionary pressures, the total number of offshore drilling units (including vessel type, jack-up type and semi-submersible type) has doubled during the last seven (7) years. And offshore petroleum exploration sites are recently expanding toward deep sea and severe weather areas. Such expansion of the activities brings a shortage of well experienced rig operators and the exploration work in such areas makes the rig operation difficult and complicated. And if a severe accident should happen due to inadequate operation, it may result in a loss of many human lives and cause a great damage to the owner and operator of the rig. Under these backgrounds, the problem of rig operation is a great issue, and an introduction of a computer system into the rig operation is getting keen interests from rig operators. In this paper, a computer system installed onboard a semi-submersible drilling unit is investigated for a purpose of assistance of the operator aboard. AIM AND CONCEPT OF THE SYSTEM Loading and stability calculation and the check of mooring performance are most fundamental in the safe operation of a semi-submersible offshore drilling unit. p. 12–57 p. 12–57

Abstract The retrofit of cathodic protection facilities to two offshore pipelines is described. The reasons for the premature failure of the initial system, and for the selection of the retrofit method are discussed. The design of the retrofit facilities, comprising sleds bearing 1.8 tonnes of aluminium alloy, is described, and results of pre and post-installation potential surveys compared. A number of conclusions for future retrofit operations are drawn. Introduction In early 1981, cathodic protection potential measurements were mode by a remote controlled vehicle (RCV) on six offshore pipelines that had been installed in 1969 – 1970. These pipelines were the first to be installed in Bass Strait (refer Figure 1) and were laid directly an the seabed. The results showed that portions of two lines - a 500 mm oil pipeline between Kingfish B and Halibut platforms and a 600 mm oil pipeline between Halibut platform and shore - were no longer fully protected. Potentials measured platform and shore - were no longer fully protected. Potentials measured on the lines were as positive as -700 mV, to a silver/silver chloride reference electrode (full protection levels are considered to have been achieved if the potential is more negative than -800 mV). Both pipelines had originally been coated with 2.5 mm of a hot applied glass fibre reinforced coal tar enamel, and a concrete weight coating varying in thickness between 25 and 75 mm. Each line had been fitted with sacrificial zinc anode bracelets, at spacings of up to 1300 m, weighing up to 320 kg and designed to last for 20 years. The RCV was used to closely examine these anodes, and it was found that the anodes had been completely consumed after only 11 years. CAUSES OF PREMATURE DEPLETION The premature depletion of the anodes is thought to have been due to a combination of the following reasons: Pipeline operating temperature: of the pipelines with anodes that were inspected, only those pipelines in hot oil service had suffered complete anode consumption. Anode depletion had occurred on onlythose portions of the lines that had carried oil at temperatures estimated to be above 60C. Ineffective pipeline/platform electrical isolation: both pipelines had faulty insulated flanges. p. 13–12 p. 13–12

Abstract Design studies for the offshore pipeline system for the North West Shelf project in Australia commenced in the early 1970's. Flow mode selection project in Australia commenced in the early 1970's. Flow mode selection resulting in a two-phase flow system for gas and condensate was completed in 1978. A diameter of 1016 mm was selected for the 134 km trunkline from the North Rankin platform to shore. During 1978 and 1979 detailed route surveys, oceanographic investigations and cyclone hindcast studies were completed, allowing detailed engineering to commence. Pipe was ordered from Japan in December 1980 and deliveries were made between April and August 1981. Pipe coating was carried out in Western Australia between August 1981 and March 1982. Pretrenching of portions of the pipeline route was completed between December 1981 and September 1982. Pipeline installation commenced in May 1982 and was completed, including post-trenching, by December 1982. Backfilling over the pipe was carried post-trenching, by December 1982. Backfilling over the pipe was carried out between August 1982 and June 1983. The tie-in to the platform and final hydrostatic test on the pipeline were completed by May 1983. Dewatering, drying and inerting is planned for October and November 1983. The slug catcher associated with the two-phase system will be completed by December 1983. The line is expected to be commissioned in June 1984. Introduction The trunkline from the North Rankin "A" platform to shore has recently been completed as the first part of the offshore pipeline system for the North West Shelf project. This pipeline originates from the platform in a water depth of 125 m, enters the mouth of Mermaid Sound, and terminates just south of Withnell Bay on the Burrup Peninsula, on the North West coastline of Western Australia (see Figure 1). The pipeline is 1016 mm (40 inches) in diameter and 134.2 km long. It will operate in two phase flow bringing both gas and condensate to the onshore plant near its landfall. A slugcatcher is under construction within the plant to receive liquid hydrocarbon slugs from the pipeline. The trunkline to shore will initially serve only the one offshore platform and operate at about 25% of its capacity to supply the Western Australian domestic gas market. The domestic gas plant on the Burrup Peninsula is being constructed by Woodside to produce pipeline quality gas for delivery to the State Energy Commission and condensate for shipment by coastal tankers. A 1500 km long onshore pipeline from the Burrup Peninsula to Perth and other localities in the south west of the State of Western Perth and other localities in the south west of the State of Western Australia is being constructed by the State Energy Commission to supply local domestic and industrial users with up to 10.9 million m3/day of gas (385 MMSCFD). p. 13–76 p. 13–76

Mieras, A.A.; BP Petroleum Development Limited; United Kingdom Abstract This paper describes the operational history to date of the Buchan Field in the British Sector of the North Sea. The development is based on subsea completions connected to a floating production facility via a subsea manifold and a tensioned multiple riser system. Stabilized crude oil is exported from the platform to a tanker via a subsea pipeline and a CALM buoy. Operational problems and successes are discussed. The Field is operated by BP Petroleum Development Limited on behalf of the Buchan Field Joint Venture Partners. The paper concludes that even in the hostile environment of the North Sea a floating production system is a viable method of producing marginal fields. It is suggested that a purpose built platform would be a better proposition than a conversion such as was used far Buchan. Careful selection of the loading system with respect to weather conditions is essential. Introduction The Buchan Field is Located approximately 160km ENE of Aberdeen and 55 km WNW of the Forties Field in water about 115m deep (Figure 2). It was discovered in August 1974 by the Transworld Group and Texaco, and further appraisal wells were drilled between then and 1976 to delineate the Field. BP Petroleum Development farmed into the license in early 1977 and took over as Operator of the development. The bulk of the Field lies within Block 21/1 with an extension into Block 20/5. p. 11–75 p. 11–75

Abstract This paper deals with facilities planning for Esso Production Malaysia Inc's (EPMI's) Semangkok oil field and is supplementary to the Semangkok Field Development Planning paper presented at this conference. The original plan was to develop the field with three platforms but further studies indicated that two platforms would reach all reserves utilizing higher angle wells. The production facilities include a manned central processing platform, Semangkok A, with gas re-injection facilities and an processing platform, Semangkok A, with gas re-injection facilities and an unmanned satellite platform, Semangkok B. Remote operation of the unmanned satellite platform is accomplished by a telemetry system operated from the central platform. Crude production is pumped to the onshore Trengganu Crude Oil Terminal (TCOT) via a pumping platform. Development planning had to consider the high CO2 content of Semongkok gas which required careful selection of materials in the facilities design. Introduction The location of Semongkok field relative to other EPMI fields in offshore Peninsular Malaysia is shown in Figure 1. Semangkok field is 87 km from Peninsular Malaysia is shown in Figure 1. Semangkok field is 87 km from the Tap is pumping platform which in turn is approximately 200 km from the onshore Trengganu Crude Oil Terminal (TCOT) near Kerteh. The Semangkok field crude reserves will be recovered from the Group E sandstones with average depths ranging from 1000 m to 1200 m. Oil accumulation is of a rim-type which is underlain by water and overlain by gas. Although the aquifer strength varies from weak to moderate no water injection is required to maintain the reservoir pressure. Produced gas will be reinjected for purposes of reservoir pressure maintenance. Compression design capacity is 1 × 10 degrees std. m3 per day. Field optimization studies have reduced the development of Semongkok field to two production platforms - namely Semangkok A, which is manned and to be a central processing platform and Semongkok B, which is unmanned and to be a minimum facility satellite platform. Semangkok A platform is on eight-legged, five-module platform with 24 well-slots and is located in 64 m of water. The jacket and deck modules were installed in July 1983. Gas compression facilities will be installed in April 1984 when drilling is in progress and production has commenced. Semangkok B is a four-legged platform containing two modules and having 18 well-slots. The modules were installed in September 1983. p. 5–65 p. 5–65

Abstract This paper discusses several subjects with respect to the burial of pipelines and transmission lines in particular and the design and pipelines and transmission lines in particular and the design and construction of bottom and scour protections for offshore structures in general. Possible incidents with pipeline and cables during installation, burying, Possible incidents with pipeline and cables during installation, burying, testing and operation are discussed as well as the environmental impact of these incidents and of burial operations. Alternative methods of protection cq. stabilization of pipelines, cables and offshore structures, using specially designed stone-dumping vessels and mattress-sinking techniques presented. presented Introduction The safety assessment of offshore structures, submarine pipelines and cables is becoming an important tool in the decision-making process of Government agencies and pipeline or cable operators. Most Government agencies do have trenching and burial cq. covering requirements. Although they vary very significantly and are continuously changing, nobody doubts the importance of such regulation nowadays. More and more pipelines and cables are laid on seabottoms all over the world and so as a result the chance of damaging a pipeline or cable is continuously increasing. Damage of a pipeline or cable can result in: The release of the contents of the pipeline causing very serious environmental impact. Very high repair costs. A loss of income in the period between the accident and the final repair. A shorter lifetime of the pipeline or cable. p. 9–35 p. 9–35

Abstract The paper mentions various factors which influence internal corrosion and how they might be controlled and monitored in submarine pipelines carrying hydro-carbon products. There is a description of factors influencing the choice of inspection areas and of inspection methods. Finally, procedures to estimate the corrosion rate/lifetime and the establishment of the allowable operating pressure are given. Introduction Experience has shown that corrosion is one of the main threats to the integrity of submarine pipelines carrying hydrocarbon products, and extensive efforts are made to monitor, control and reduce the corrosion problem. problem. In order that a system operates during the service phase with a minimum of problems, it is important that the corrosion control system is considered problems, it is important that the corrosion control system is considered early in the design stage. During this early consideration it is necessary that all relevant information is available. This might include earlier experience, research work, etc which con be considered as "Know how", ref. Figure 1. The cycle presented in Figure 1 is schematic but indicative of the dynamic interaction between experience gained, research follow up and the use of rules, codes and specifications to give guidance during design. Ideally, the design stage would eliminate any further consideration of corrosion. In practice, that is not possible. During design certain assumptions must be made about the nature of the corrosive environment. During service, the environment must therefore be monitored to ensure that there is no significant deviation from these. Further, some material loss is almost always experienced. It is then necessary to ensure that this is kept within acceptable limits or to take action of some type if it appears to be unacceptable. Such action can then feedback to the Know how" part of the cycle and hopefully prevent a similar situation arising again. This paper will discuss some of the above aspects, starting with a brief discussion of the problem itself - CORROSION. Building upon the principles outlined in that discussion, various methods of control will be mentioned including a consideration of the important design stage. This in turn is followed by a section dealing with various monitoring and inspection techniques leading to the concluding sections. p. 13–32 p. 13–32

Simon, Philip D., Executive Vice-President, Operations Norton Corrosion Limited, Inc. United States of America Abstract This paper presents test data, evaluation and recommendations resulting from an investigate cathodic protection and coating integrity survey of a twenty year old, onshore crude oil pipeline. The pipeline discussed is 20 inches (508 mm) in diameter, 233 kilometers long and originates at a pumping facility in an inland oil field. The pipeline runs through pumping facility in an inland oil field. The pipeline runs through mountainous terrain, low lying marshland and terminates at a twin 16 inch submarine crossing. The pipeline is located in Southern Kalimantan, Indonesia and is p art of the Pertamina Unit IV installation. The field testing was performed by Norton Corrosion Limited (NCL) during the months of March ad April, 1983 and was done concurrently with river crossing profile work by Sterling Energy and Resource Technologies, Limited. The purpose of the survey was to determine the condition of the pipeline and the condition and effectiveness of existing corrosion control pipeline and the condition and effectiveness of existing corrosion control measures. The pipeline had experienced an increasing number of leaks in recent years and it was necessary to know the physical condition of the line and what could be done to extend its useful life. The present and future integrity of the pipeline was critical to the clients' planning in that this particular line is the only onshore connection between the field and new refinery which was nearing completion. CORROSION AND CATHODIC PROTECTION FUNDAMENTALS The corrosion of metals is an electrochemical process. That is to say, it is a chemical reaction which involves the transfer of electrons. Metal is lost at the anode (oxidation reaction) and atomic hydrogen is produced at the cathode (reduction reaction). A corrosion cell is a system in which a cathode and an anode are electrically connected and submerged in a common electrolyte. When this oxidation-reduction reaction occurs, a DC electrical current will flow with metal lost at the anode. This system is called a corrosion cell. A corrosion cell will be formed when the following conditions are met: There must be a cathode and an anode with a difference in electromotive force (driving voltage). The anode and cathode must be electrically connected by a metallic path. The anode and cathode must be immersed in a common (the same)electrolyte. p. 13–103 p. 13–103

Abstract This paper addresses the basic configuration of simple subsea completions. In an attempt to present an overview of the options open to an operator, examples are taken from various systems which have been designed and/or installed. Features from more advanced designs have become available to upgrade the state of the art in this field. It should be emphasized that like land and platform wellheads and trees, a vast array of options and customized designs are available to meet particular requirements in this environment, and it is difficult to propose particular requirements in this environment, and it is difficult to propose a standard completion. To enable a concise view of a subsea completion all major areas have been touched, from the drilling equipment required, the interface equipment and finally the tree and control systems typically available. WELLHEADS Wellheads for offshore wells fall into three main categories. Marine Wellheads for Floating drilling units. Mudline Suspension/Surface Wellhead for 'fixed bottom' Jackup units. A Hybrid System of 1 and 2 generally a special purpose design for specific applications. MARINE WELLHEADS (See Figure 1) This type of wellhead is located on the ocean floor level. Its primary functions are: To provide a termination of the casing strings with a means to connect the primary well pressure control equipment. Provide a means of guidance for the Blowout Preventor stack, and guidance of any additional equipment such as a subsea tree (if required). Provide a means of suspending the various casing strings and sealing the annuli. The footing rig used to drill the well is equipped with a subsea Blowout Preventor stack (BOP). Preventor stack (BOP). p. 10–1 p. 10–1

Introduction While the concept of offshore tanker loading has been around for many years, it was not until the early 1970's that the idea of employing a Single Point Mooring (SPM) terminal as an integral part of on offshore production facility achieved wide industry acceptance. In this production facility achieved wide industry acceptance. In this application, the SPM provides both a permanent (or semi-permanent) mooring for the tanker and a means for transporting oil from the seafloor to the tanker. The SPM thus eliminates the requirement for a pipeline from the offshore field to the shore which often significantly reduces the overall project cost and may allow development of marginal fields which have project cost and may allow development of marginal fields which have insufficient recoverable reserves to justify a pipeline system. A second economic consideration in the election to use offshore loading is that it makes it possible to ship crude and receive income as soon as oil is available for a relatively small investment and in a relatively short time frame. Thus, production from initial wells con be generating cash flow while the drilling program continues with delineation of the reservoir. Even if the economics can support the cost of a pipeline, on offshore loading system ensures income during the sometimes lengthy design and construction period and is often retained subsequent to pipeline completion as a backup system in the event of pipeline outage. Selection of on offshore loading scenario obviously will often require in depth analysis of many economic considerations. However, the fact that viable concepts for offshore loading are available is of prime importance and offers a much greater flexibility to the operator in his planning than previously existed. previously existed. THE SPM CONCEPT There are several distinct types of SPM's, all of which share two common features: They all provide a single point which may rotate 360 degrees in the horizontal plane, to which the tanker moors its bow (or stern) viahawsers or structural steel frame. They all employ fluid transfer systems which ore capable of 360degrees rotation in the horizontal plane. The tanker moored only by connection to its bow or stern is free to "weathervane" about the single point mooring and, thus, stay oriented head-on into the prevailing environment. p. 11–32 p. 11–32

Khan, Saeed U.; R J Brown and Associates (Far East) Pte Ltd, Singapore Abstract The advances in offshore pipeline technology, in recent years, have been achieved by using innovative engineering to reduce construction risks and total capital costs. New design concepts and installation techniques namely: pipeline installation using the bottom tow method, pipe connections using the deflect-to-connect method and pipe trenching using marine plows have successfully been used in the North Sea, Canadian Arctic, South China Sea and Australian waters and which have resulted in significant cost savings in the material and installation costs. Introduction With the spiraling hikes in the price of oil in the early seventies, the search and development of offshore oil/gas fields even in more non-traditional and remote areas with adverse environmental conditions, where equity capital and return ratios for such developments were previously considered significantly unattractive, was accelerated. The previously considered significantly unattractive, was accelerated. The requirements of high financial outlays for such offshore projects clearly dictated the necessity of cost savings in the materials and installation costs in order to make such developments economically viable. This obviously prompted concerted efforts towards the development of new design concepts, construction techniques and a so more sophisticated engineering analyses to reduce the construction risks and capital costs and also to alleviate maintenance and repair problems of such oil/gas transportation systems. The more severe requirements of pipelines long term stability in harsh environment and remote areas where maintenance and repair problems might result in higher costs than the actual installation cost put more emphasis on front-end engineering to obtain optimum solutions and cost-effective pipe installation and burial techniques. New design concepts and construction techniques have already proven their practicality and cost effectiveness especially in those areas where previously it was thought to be either too difficult or too expensive to develop. This paper discusses the development and successful use of three such design concepts and installation and techniques for pipelines. These are: – pipeline installations using the bottom tow method; – remote connections by the deflect-to-connect methods; – pipe trenching using the marine plows. p. 13–58 p. 13–58

This paper presents the past, present and future of deepwater exploration drilling (600 to 13,000 ft.). Specifically presented are the technical achievements that were necessary to move beyond 600 ft. water depths and to provide the capability to drill in 13,000 ft. of water. Also presented are several examples of these technical achievements which have been experienced by exploration drilling units in the deepwater environments during the past 10 years. Introduction The Petroleum Industry over the past 100 years has moved from drilling offshore on fixed platforms which extended from the shoreline to floating drilling far offshore in water depths greater than 5.000 ft. The environment offshore, which our industry has confronted and worked in, has been more challenging and rewarding than man's trips to the moon. Offshore drilling has been challenged by water depth, currents, tides, waves, wind, icebergs, pack ice, ice floes and distances. Not all places in the world have any or all of these environments in a hostile condition. The world's oceans have challenged man's imagination, fortitude and technological capabilities for centuries on end, dating back to the days of Columbus and Magellan and including more recently highly, sophisticated operations such as drilling in 5,000 ft. of water or drilling in offshore areas where ice and icebergs are common occurrences at the drill site. The technology of drilling a hole and the equipment needed to drill a hole have been perfected for inland operations for the past 70 years. This same technology and equipment have for the past 25 years have been extended offshore, first on small platforms. then on barges, jackups, mobile platforms, and floating ships and semi-submersibles. Examples of hostile environments which the petroleum industry has confronted are illustrated in Figure 1. These include pack ice in the Arctic: moving ice in Cook Inlet. Alaska: icebergs in Greenland; hurricane storm waves of 70 ft. in Ireland; deepwater in 5,000 ft. offshore Canada, currents of 4 knots offshore Thailand: moving ocean floor sediments in South America; tides of 30 ft. offshore Canada. and winds of 100 knots in the North Sea. The trend in offshore exploration clearly shows that the industry will and can move to deeper water environments to drill and explore for oil and gas (Figure 2). Records show that it took the industry 20 years to move floating drilling from 100 ft. water depths to 1,400 ft. yet in the past 10 years we have extended the water depth an additional 3,600 ft., from 1,400 ft. to 5,000 ft. We have now drilled more than 400 exploration wells in the water depths of 600 ft. to 5,000 ft. The future indicates we will be drilling in over 5,000 ft. water depths next year and 13,000 ft. by the late 1980's. As water depths increased, floating drilling became necessary. This required three major technological extensions of knowhow and innovation. These include: Motion. The rig no longer has bottom support. Mooring. The floating unit must be held against environments. Subsea. The blowout preventer is now Wow water. In the years 1953 through 1964, the oil industry was developing the technology and equipment to work from floating vessels while drilling exploration wells. All of the above major technological extensions required many hours of engineering, new types of equipment, and years of operating experience to achieve the confidence of the oil industry that exploration from floating drilling was safe and practical. These advances are now routine. Motion. We continue practical. These advances are now routine. Motion. We continue drilling operations in 40 ft. waves and 60 knot winds. Mooring. We have drilled successfully in 5,000 ft. water depths and have stayed on location in 92 ft. waves and 100 knot winds subsea. Safe. remote operations, subsea BOP control, etc., have been routine in the 4,000 wells drilled with subsea equipment offshore. The past 10 years, 1971 to 1981. have required major technical achievements in deepwater exploration drilling technology. Dynamic stationing with ships like the SEDCO 445 (Figure 3) had just gone into operation in 1971 in 1,400 ft. water depths. The past 10 years, dynamically stationed drill ships similar to the SEDCO 445 have continued to operate without anchor mooring while drilling wells in water depths between 600 to 5,000 ft. Presently our capability is that equipment and technology are available to drill in 8,000 ft. of water (Figure 2). The achievements necessary to move floating drilling from 600 ft. water depths to 8,000 ft. water depths have been: Mooring. Development of dynamic stationing to replace mooring systems. Re-Entry. Development of acoustic TV re-entry, to replace guideline systems. BOP Controls. Development of electro/ hydraulic controls to replace hydraulic operations which were too slow. Riser. Development of couplings which can stand high tensions and fatigue equal to pipe body. Development of reliable buoyancy materials to reduce riser tension requirements. The technology available today gives the industry the capability, to drill exploration wells in 8,000 ft. of water. The only limitations to extending this capability, to 13,000 ft. water depth are (a) riser handling techniques and (b) formation fracture gradients in deepwater. Risers can be designed and built to be used in this water depth, but the handling, storing and operating procedures for storm disconnect require additional steps in technology. This step in technology is not great but it does require the incentive of the industry before equipment will be built and procedures established. Formation fracture gradients in very deep water present a major problem and only setting casing strings at proper depths will solve problem and only setting casing strings at proper depths will solve this problem. Further development of subsea wellheads is required but this is not a problem and can be solved when the need for the equipment is demanded. The U.S. National Science Foundation is now in Phase I of a program to drill on the Ocean Margin for scientific information. program to drill on the Ocean Margin for scientific information. The program will require using subsea well control equipment. The plan is to drill approximately ten wells in water depths of 9,000 to plan is to drill approximately ten wells in water depths of 9,000 to 13,000 ft. Other programs for deepwater are under study in France, Italy, the U.K., Canada, Norway, Germany and Japan. There are no major obstacles to safely and efficiently drill exploration wells in 13,000 ft. water depth.

Drilling and production in deeper water set new requirements to the design of marine risers. In this paper the most common methods of dynamic analysis of such risers are reviewed and discussed with reference to a set of full scale data. The measurements were taken by CONOCO in 1975 on a drilling riser operated from a semisubmersible. A spectral approach is applied in evaluating these data and the results include standard deviations, response, spectra and transfer functions. The quality of the data is found to be generally good. Some doubt is express as to the exact conditions at the top support, but it is still considered that important trends are revealed. In the theoretical analysis four different computer are investigated, covering six different methods. The programs employ either linearized frequency domain solution or time integration techniques with varying degrees of non-linearities included and for either regular waves or irregular sea. Most of comparisons with measurements are carried out in terms of linearized transfer functions. The validity of this approach is discussed as part of the evaluation of the results. Introduction Riser analysis methods have receive considerable attention in the technical literature but little has been published on the verification of such methods against full scale measurements. The mason for this is that few instrumented programs have been conducted, and that the resulting data usually have been kept confidential. In 1974 CONOCO conducted an instrumented investigation on a drilling riser from the submersible Sedco 702 while operating an the Hutton field in the North Sea. The resulting raw data were offered for sale and Det norske Vertias, Kongsberg Vapenfabrikk and Norsk Hydro joined Aker Engineering in an effort to analyse this data and to compare the results against several available riser analysis programs. The instrumentation adopted by CONOCO was quite extensive, but for the present paper the following instrumentation has been made use of : – wave rider – platform mounted wave staff with heave compensating accelerometers – horizontal platform offset by acoustic position indicator – bending strain gauges at four locations along the riser The reduction of the raw dam was done by the SAMPAN data analysis package (Ref. 1). Generally the sea states analysed were found to contain relatively moderate wave conditions. For this presentation three sea states were selected (A, I and R) Table 1 that presentation three sea states were selected (A, I and R) Table 1 that were found representative for the range of sea states. Sea state 1 with significant waveheight of 8.4 m was the highest sea state measured. Four different analysis programs containing six different methods were used in the present comparison: – SEARISER (Ref. 2) Non-linear time integration according to the Wilson -method. Both regular and irregular seas may be synthesized. – RISANA (Ref. 3) Non-linear time integration according to the Newmark beta - method. Regular wave only. – CONOCO STATIC/DYNAMIC (Ref. 4) regular waves. – NV457 (Ref. 5) Several methods are included but the ones used here am the stochastic linearized and directly solved frequency method and nonlinear irregular sea simulation according to Wilson - method. A brief review of the theoretical basis for the methods adopted are given in the following. RISER DYNAMICS Equations of Motion The equation of motion of a segment of a marine riser may be written as : Mx + B/Vrel/Vrel + T'x" + Elx" + Wx' = F where: M is the riser mass including added mass x is the riser acceleration B is the unit drag force Vrel - is the relative velocity between the riser and the surrounding water, ie. vrel = × + Cu - w where Cu is the current velocity and w is the wave particle velocity T - is the so called "effective" tension which is the true tension plus buoyancy effects (Ref. 6). x" - is the riser curvature or the second derivative of the deflected shape EI - is the riser bending stiffness x"" - is the forth derivative of the distorted riser shape W' - is the inclination of the riser to the vertical F - is excitation force which consists only of wave inertia since wave drag has already been included on the other side of the other side of the equal sign

The use of a polymeric drag reducer to increase the flow capacity of crude oil pipelines is described in this paper. The first commercial drag reducer application began in July 1979, in the Trans Alaska Pipeline. By 1980, flow through the TAPS line had increased to the 1.5 million bbl/D (9,940 m3/h) level. Approximately 200,000 bbl/D (1,300 m3/h) of this throughput was a direct result of injecting a drag reducing additive. In 1981, drag reducers continue to contribute to the TAPS throughput In commercial operations, a drag reducer must be shear stable during line flow and must be effective at very low concentrations. In addition, the treated crude must not cause any downstream refining problems. CDR Drag Reducer meets these requirements and has proven to be viable means of increasing pipeline flow rates. Recent modifications of the polymeric additive have raised drag reducer performance levels. New performance data from 8, 12, and 48-inch diameter performance levels. New performance data from 8, 12, and 48-inch diameter pipelines are discussed. Offshore production operations would clearly pipelines are discussed. Offshore production operations would clearly benefit from improved performance. Shipping and handling of products present a special problem in offshore operations … particularly in present a special problem in offshore operations … particularly in periods with bad weather. Reducing the required storage will periods with bad weather. Reducing the required storage will proportionally reduce platform space and weight requirements. proportionally reduce platform space and weight requirements. Introduction Drag reducers have been known for many years., Drag reduction has been defined as the increase in pumpability of a fluid caused by the addition of small amounts of an additive to the fluid. The relative performance of a drag reducer may be expressed in terms of percent drag reduction. At a constant flow rate, percent drag percent drag reduction. At a constant flow rate, percent drag reduction is defined as (1) where Delta P is the pressure drop of the untreated fluid and Delta P' is the pressure drop of the fluid containing the drag reducer. The increased pumpability can usually be used to increase flow rate by increasing the pressure drop. P', back to the initial level for the untreated fluid. The percent throughput increase, %F.I., can be estimated using the following equation: (2) Drag reducers received a great deal of attention in the 1960's. A number of polymer candidates were identified. However, the incentives for pipeline use were not attractive enough to justify commercial use. During 1977 discussions between Alyeska Pipeline Service Company and Conoco began on the use of drag reducers. This led to the First commercial use of CDR (TM) Drag Reducer in 1979. This test program leading to this application was described in a previous publication. This paper briefly reviews that test program and describes several other subsequent pipeline tests. It also describes the development of a more effective drag reducer. To qualify as a drag reducer candidate for crude oil pipelines a polymer must (1) be effective at low concentrations, (2) be relatively polymer must (1) be effective at low concentrations, (2) be relatively shear stable during the flow, and (3) cause no downstream refining problems. problems. Low concentration levels are necessary since continued injection is required. The drag reducer reduces the energy lost in turbulent flow by modifying the sublaminar layer and interaction between the fluid and pipe wall. However, it does not treat or coat the pipe wall. The drag reducer must maintain its effectiveness as the fluid moves down the pipeline between booster pump stations. In dilute solutions. the polymer molecules are degraded by the shearing action of the pipeline booster pumps. Therefore. the drag reducer must be injected in a concentrated form downstream of the pipeline pumps. pumps. For the past two years the 1.5 million bbl/D (9,940 m3/h) of North Slope crude, or approximately ten percent of all crude oil refined in the United States, has contained drag reducers. By law, North Slope crude cannot be exported and, therefore, has been shipped to U.S.A. refineries. No problems have been encountered either during the initial carefully monitored full scale refinery tests or in normal operations of refineries throughout the U.S. Initially TAPS was constructed without Pump Stations No. 2,5,7, and 11. Its capacity with this configuration was 1.2 million bbl/D (7,952 m3/h). The 1979 tests were designed to evaluate the flow improvement capabilities of drag reducer as a partial substitute for two of the booster pump stations. In July 1979 continuous injection of drag reducer was begun. During 1980, the mechanical capacity of the pipeline was increased and the daily flow rate was increased to over 1,500,000 bbl/D (9,940 m3/h). About 200,000 bbl/D (1,300 m3h) of this flow increase was the result of injecting a drag reducer. The improved drag reducer performance described in this paper could result in more wide spread use of drag reducers both onshore and offshore. It could even become an economic substitute for part of the pumping energy for many pipelines, particularly with the forecasted increase of energy cost in the future. Pipeline Drag Reduction Tests Pipeline Drag Reduction Tests Drag reduction tests were performed in four different pipelines ranging from 8-inch to 48-inch. Each test was designed to test drag reducer products at two or more velocities.

The development of the Udang "B" project in the Indonesian Natuna Sea required the installation of two insulated submarine pipelines in nearly 300 feet of water. These pipelines carry 100 degrees F pourpoint crude, water, gas from the recently installed Udang "B" platform to the Udang "A" platform. At the Udang "A" platform, the produced fluids are processed. platform. At the Udang "A" platform, the produced fluids are processed. The crude oil is then transported to a permanently moored storage tanker through two other insulated submarine pipelines. The Udang "B" pipelines have a 12 ¾ inch inner pipe with an 18 inch outer pipe. The annulus between the two pipes is filled with a polyurethane pipe. The annulus between the two pipes is filled with a polyurethane insulating foam. That annular cavity is then sealed with a steel washer plate at either end of the insulated pipe joint. The pipeline system is plate at either end of the insulated pipe joint. The pipeline system is designed to withstand at 190 degrees F operating temperature and to comply fully with applicable pipeline codes. The pipeline is designed so that the polyurethane insulating foam is protected from the 140 psi external polyurethane insulating foam is protected from the 140 psi external hydrostatic pressure. The pipelines were installed offshore using a lay barge with innovative methods used at the field joints to insure the uniform structural integrity of the pipeline and the continuity of the insulation system. The risers were also insulated and installed in one piece with a flanged connection completed on the seafloor to connect the riser with pipeline. Third party underwater inspection of the jacket, riser, and pipeline connections was provided by a remote controlled vehicle (RCV). provided by a remote controlled vehicle (RCV). This paper discusses the insulated pipeline system as it evolved through the design, onshore pipe insulation and joint fabrication, and offshore construction. The paper reviews the design and construction techniques used successfully for these offshore insulated pipelines. These techniques could be applicable for other similar deep water insulated pipeline applications. Introduction The Continental Oil Company of Indonesia as operator for itself Java Gulf Limited, Getty Oil International (Indonesia) Ltd and Inpex Natuna Limited operates the Udang production facility under a production sharing contract with Pertamina. This facility is located in 300 feet of water in the Indonesian Natuna Sea about 750 air statute miles north of Jakarta and 50 miles north of the Anambas Islands, the nearest landfall. Two combination drilling and production platforms am in operation in conjunction with a moored production platforms am in operation in conjunction with a moored storage tanker and export facility. The two platforms and the tanker are linked by dual subsea insulated pipelines. The Udang 'A' facility, installed in 1978, utilizes a 14 slot, 8 pile, 2300 ton jacket, with attendant flam structure. Three stage separation and treating facilities are on the platform as well as emergency accommodations. The storage tanker, the "Udang Natuna", is permanently moored approximately 6,100 feet southeast of the Udang 'A' platform. Two insulated subsea pipelines connect the Udang 'A' platform with a PLEM (pipeline and manifold) beneath the loading buoy on the seafloor. These pipelines are a 8 5/8 inch pipe inside of a 12 ¾ inch pipe with insulating foam in the annulus. The Udang 'B' facility, installed in 1980, is located, 12,500 feet to the southwest of the Udang 'A' platform. The Udang 'B' jacket, also located in 300 feet of water, is a 15 well, 8 pile 2,160 ton jacket with emergency living quarters and well test separation. The crude oil, associated gas, and produced water flow through dual subsea insulated pipelines from the 'B' facility to the 'A' facility for further processing. These two pipelines have a 12 ¾ inch inner pipe and an processing. These two pipelines have a 12 ¾ inch inner pipe and an 18" outer pipe with insulating polyurethane foam in the annulus. The Udang crude has an API gravity of 40 degrees but its pourpoint is 100 degrees F. Consequently in order to flow it must be maintained at an elevated temperature. The maximum anticipated crude temperature is 190 degrees F. A minimum temperature of 150 degrees F is maintained in the storage tanker by heating the storage tanks. Because of the high crude pourpoint and the necessity of maintaining the crude at an elevated temperature, all Udang subsea pipeline systems have a redundant pipeline installed. This dual pipeline systems have a redundant pipeline installed. This dual pipeline system allows the pipeline contents to be circulated in the event pipeline system allows the pipeline contents to be circulated in the event of equipment failure or scheduled maintenance. this circulation, in conjunction with the addition of heat as the pipeline circulates through the "A" facility, will prevent the formation of gels which could plug the pipeline. The pipeline insulation also increases the allowable pipeline shut-in time before circulation and heat imput are required. Design The pipeline and risers designed to be in compliance with the det Norske Veritas (DNV) pipeline code. Because of the high crude temperature and the need for insulating the pipeline, the design of the pipeline system had to accomodate some interesting features. Thermal Design Consideration For Pipeline The thermal insulation system, which was developed by Conoco during 1975 – 1971 for use on the Udang 'A' project, was used on the Udang 'B' pipelines. The design utilizes a closed cell polyrethane insulating foam with a heat transfer coefficient of 0.15 BTU-IN/ deg. F-F+ 2 hour or less. The foam weighed 3.2 pounds per cubic foot. A minimum foam thickness of 1.375 inches was required for the Udang 'B' pipelines. Because the Udang pipelines are in 300 feet of water the polyurethane foam must be completely protected from the external hydrostatic head. The head pressure in 300 feet of water is sufficient to cause seawater to infiltrate the foam causing it to lose its insulating capability. To eliminate this problem, the insulated 12 inch pipe joint was encapulsated within an 18 inch pipe. Only the ends of the 12 inch pipe joint extended past the end of the 18 inch outer pipe with the two pipes joined by a steel end washer or disc. The design of the pipeline and riser system to withstand the thermal expansion forces was a major consideration in the design effort. For design purposes, 190 degrees F was selected as the maximum pipeline temperature and 62 degrees F was selected as the sea bottom water temperature. This differential temperature of 128 degrees F was accommodated in the design. The pipeline and riser system design was analyzed using a conventional analytical technique modified slightly to reflect the use of an outer and inner pipe. The resistance of the sea bottom to the pipelines' axial expansion was considered.

Application of adequate corrosion control technique to achieve the necessary safety and desired life of offshore process facilities are considered primarily tasks of operators and authorities. The paper will describe primarily tasks of operators and authorities. The paper will describe different types of corrosion hazards and consequences of a corrosion failure for the different components of a process system. The following aspects will be considered: – accessibility of components – consequences of a corrosion failure – corrosion types such as CO2-corrosion, H2S-corrosion, erosion corrosion, etc. – corrosion control techniques such as inhibitors, coating, corrosion resistant steels, etc. – corrosion monitoring with special emphasis to procedures for thickness measurements The work is primarily based on experiences from design evaluation and inspection of equipment which have been in service, but it is also supplemented by laboratory testing of corrosion rates and inhibitors. The so-called "sweet" corrosion which is caused by corrosive gases such as CO2 and chlorides dissolved in the produced water is influenced by a number of parameters which are discussed. The "sour" corrosion type materialized by parameters which are discussed. The "sour" corrosion type materialized by hydrogen induced stress corrosion is caused by H2S and water when unsuitable materials used. Requirements on selection of materials and fabrication procedures and testing methods for application under sour conditions are procedures and testing methods for application under sour conditions are reviewed. The application of corrosion control techniques to achieve the necessary safety and desired life of the equipment are considered primary tasks of both the operators and the authorities and different approaches may be used to achieve this goal. Introduction In a simplified form the main steps in treatment of hydrocarbons offshore are indicated in Figure 1. In addition to the steps shown on Figure 12, different utility systems such as hydraulic system, instrument air, fire water etc, are of importance for the safe operation of the production of hydrocarbons. The type of equipment being installed on the platforms is similar to equipment installed onshore, for instance in refineries, but the space is more limited. As every square metre offshore is so costly, the equipment is very compact.