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Collaborating Authors
United Kingdom
Use of Compositional Simulation in the Management of Arun Gas Condensate Reservoir
Sutan-Assin, T. (Mobil Oil Indonesia) | Rastogi, S.C. (Mobil Oil Indonesia) | Abdullah, M. (Mobil Oil Indonesia) | Hidayat, D. (BKKA - Pertamina (Indonesia)) | Bette, S. (Mobil R and D Corp. (USA)) | Heineman, R.F. (Mobil R and D Corp. (USA))
Abstract This paper describes the simulation of the Arun gas condensate reservoir using Mobil's fully compositional simulator, COSMOS (Compositional System Mobil Oil Simulator). The reservoir is a Miocene carbonate reef complex which occurs at a depth of approximately 10.000 feet, and is up to 1,000 feet thick in some areas. The Arun reservoir is a compositionally dynamic system. The purpose of this simulation study was to predict future reservoir performance under various demand scenarios and optimize gas and NGL recovery. The simulation mode utilizes the recovery. The simulation mode utilizes the Peng-Robinson equation of state to account for the compositionally dynamic behavior of the reservoir in predictions of future performance. The equation of state was modified by Mobil to incorporate special features for Arun such as water vaporization in the reservoir under high temperature conditions. A significant amount of time was spent on the geologic description of the field and initial data preparation, of the field and initial data preparation, which contributed to a good match of the historical data. The simulation model will serve as a reservoir management and planning tool to evaluate future operating strategies in the field. The technology presented in this paper is applicable to the management of other gas condensate reservoirs which exhibit physical phenomenal such as retrograde condensation, revaporization, and water vaporization. Introduction The Arun Field is located on the northern coast of Aceh Province in North Sumatra. The field was discovered in 1971 and is a giant gas condensate reservoir. Mobil Oil Indonesia operates the field as a Production Sharing Contractor for Pertamina. Gas is produced from the Arun Limestone at a depth of approximately 10,000 feet subsea. The gas pay is up to 1,000 thick in some areas. The initial reservoir pressure was 7,100 psig at the datum of 10,050 feet subsea, and is consequently overpressured. The temperature is 352 deg. F at this datum. At discovery, the reservoir was above the dew point, and had a stabilized condensate/gas ratio of about 48 STB/MMscf of water-free wellstream gas. The reservoir is underlain by an aquifer with a gas-water contact at about 10,600 feet subsea. Reservoir fluid properties and average rock properties and given in Table 1. The Arun Field began production in 1977. Field development was based on a cluster concept whereby only small areas of land are required for surface production and drilling facilities. This was done to minimize surface disruption to native farming and to the local community. There are four clusters in the field, each cluster designed to contain a maximum of sixteen wells. Producing wells are drilled directionally from these clusters. The gas is produced under a gas cycling scheme to maximize condensate recovery. Currently, there are ten gas injection wells located on the downdip perimeter of the field. The gas and condensate are delivered to the P.T. Arun LNG Plant for processing and liquefaction prior to export (Figure 1). The field production at present is about 2700 MMscf/D of separator gas, of which 800 MMscf/D are reinjected, 35 MMscf/D are used for fuel in the field, land 1865 MMscf/D are delivered to a 42-inch gas pipeline to supply two fertilizer plants and the P.T. Arun LNG Plant. About 135,000 bbl/d of unstabilized condensate are delivered to the P.T. Arun LNG Plant through a 20-inch pipeline. The Arun reservoir is a compositionally dynamic system. With pressure depletion, the water content of the reservoir gas increases significantly due to water vaporization under the high temperature conditions. Secondly, retrograde condensation and condensate revaporization effects impact compositional performance. Furthermore, injection of lean gas changes the fluid composition within the reservoir and reduces dew point pressure and hydrocarbon yields. Dissolution of hydrocarbons and carbon dioxide from both connate water and the aquifer also contribute to compositional changes. To properly fully compositional model was employed to simulate the field. P. 601^
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.54)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 49/6a > Ann Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 48/10a > Ann Field > Rotliegend Formation (0.99)
- Asia > Indonesia > Sumatra > Aceh > North Sumatra Basin > B Block > Arun Field (0.99)
As banker to the world petroleum industry, Chase naturally has an interest in the outlook for oil and natural gas. what will he the demand for oil? How will it be met, and at what price? And, of course, what will be the future financing needs of the industry? The report that I am presenting to you today is by no means the last word on this subject. It represents just one view of the future, but one that is built around clearly defined assumptions. As we make further progress in modelling the financial side of the industry, we will be able to test other views of the future, which we will present in future reports. Any attempt to assess the future financing needs of the petroleum industry must be set in a specific framework petroleum industry must be set in a specific framework reflecting future economic growths future energy needs and the outlook for oil supply and demand in particular. These factors are all linked, although the linkage is flexible, not fixed. For example, it changes with changes in relative prices, among other things.
- North America > United States (0.48)
- Asia > China (0.31)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.94)
- North America > United States (0.89)
- (6 more...)
Summary Following a long quit spell since the peaks of 1974 the Asia Pacific region has again come back into the news, with an overall increase in activity throughout the region, rather than concentrated in any one country. The authors suggest that the improved scenario is the result of appreciation that there are still excellent opportunities and that legislation is competitive in the region. There continues to be a wide selection of opportunities in every geological sphere, of every size, providing incentive for both the largest and smallest providing incentive for both the largest and smallest companies. Costs, while increasing, have not risen as staggeringly as they have in other areas of the world, as in the North Sea, and entry expenditures such as bonuses and work obligations, are modest relative to the large areas and typical block sizes. With a stable or softening oil price, the authors foresee a growth in Asia Pacific activity and achievement of an all time high in the 1982–83 period. SIGNATURE BONUSES AND WORK COMMITMENTS The Asia Pacific area, as shown by Table 1, has very modest signature bonuses and minimum work commitments in terms of dollars per acre, particularly when we compare these to figures in the North Sea or in the Gulf of Mexico. Work commitments in fact represent the significant increase in entry costs in the region but are still modest relative to opportunities. These low entry costs are one of the reasons why the region continues to attract significant exploration. Neither the absolute numbers. ranging on our table from 7 million to 60 million dollars nor the dollars per acre, are particularly high relative to the prospects. LEASED ACREAGE SIZES Conversely the block sizes typically totaling from half a million to over three million acres (Table) gives exploration teams the opportunity to search for a variety of prospects and opportunities within the leased acreage. It also affords the opportunity in many cases for farm-out since the acreage is large enough to support a variety of geological plays which are unlikely to be tested by one or even a dozen holes. To put these block sizes into context, the millions of acre packages available under a single contract in the Asia Pacific region, compares with a mere 50,000 – 60,000 acres in the North Sea and as little as 2,500 acres in the Gulf of Mexico. HISTORICAL ACTIVITY Table 3 makes it clear that the decline in major exploration activity has reversed and the peak of 158 wells reached in 1974, has been equated in 1981 with 157 exploration wells being drilled. This is 250 percent from the lows of 1976 and 1977, and up 50 percent on 1979 figures. Current plans suggest the 1982 figures will surpass these 1974 and 1981 highs. With some 80 mobile rigs in the region (1/8 of the world mobile rig fleet) it is reasonable to assume expanded capacity for exploration in the region in the 1982/83 period will lead to significant additional activity. NUMBER OF OPERATORS Table 4 shows the approximate number of operators in each country. While it must be accepted that some of the small independents listed in this Table may not be operators in the strict sense of the word, it does give some indication of the relative activity in the various countries. The activity ranges from Australia where there is an active domestic stock market opportunity for small independents through to Malaysia, largely dominated by three majors and a national oil company. The Table, as shown, includes in the category of majors. certain significant independents and/or quasi-national oil companies. EXPLORATION AND ACTIVITY IN 1982 An Asia Pacific Exploration Activity and Expenditure forecast for 1982 is shown on Table 5. It indicates an estimate of offshore and onshore activity. The costs in this Table are based on an assumption that average exploration costs are a function of rig activity both on land and offshore and are not meant to give an indication of individual companies' budgets for particular areas concerned, but rather a comparative yardstick. It also assumes that a number of land and offshore rigs will work on exploration, but in practice discoveries could move these rigs to delineation and development drilling during the year.
- Asia (1.00)
- Europe > United Kingdom > North Sea (0.66)
- Europe > Norway > North Sea (0.66)
- (3 more...)
During the last two years Mobil has conducted in aggressive program of seismic work, wildcat and appraisal offshore North Sumatra. At times up to 3 drillships or semi-submersibles were active. Activity focussed on the NSB area offshore NW Sumatra where a significant gas discovery (NSB-A1) in 357 feet of water was known from earlier drilling. Seismic work in 1979–80, hindered by positioning problems revealed a province of Miocene pinnacle reefs. Up to 70 reefs were mapped in an area of 1800 square kilometers on the Malacca Shelf. Eleven new wildcats were drilled resulting in 7 oil and gas discoveries. Most reefs am pinnacle-like with up to 1100 feet of vertical and up to 3000 acres of areal closure. At NSB-A gas field a "build-out" reef complex developed, with some 10,000 acres of areal closure. Reefs grew preferentially on pre-existing basement high trends. Dominant organisms preferentially on pre-existing basement high trends. Dominant organisms include massive and platy corals, calcareous algae, bivalves, echinoids and liner foraminifera. Secondary processes of solution, recrystalization, chalkification and dolomitization over-rode the original reef facies and altered reservoir properties. Limestone with good secondary porosity appears to be restricted to regionally high areas which were subaerially exposed. Dolomitization seems to be erratic both in geographic distribution and in it effect on porosity. Commercial gas reserves in the order of 2 TCF have been established in four separate fields. The gas contains up to 1 – 15 percent H2S and CO2 content is 28 – 31%. For production purposes offshore dehydration will compression facilities will be required plus a 100 km pipeline to the LNG plant at Lho Seumawe. Some of the southeasterly wells tested high gravity, low pour-point crude at rates of 4000 – 5600 b/d. At present plans are being developed for a floating oil production system utilizing subsea completions, a test barge, SPM loading and tanker storage. During the last two years Mobil Exploration Indonesia his conducted an active exploration/appraisal program in the Malacca Straits, offshore North Sumatra. At times up to 2 drillships and one semi-submersible were active. Fig. 1 shows the location of the NSB are situated about 60 km offshore in approximately 350 feet of water. This block of acreage, some 2.5 million acres in size, lies on the north side of the North Sumatra basin and on the west flank of the Sunda Shelf. Stratigraphy Fig. 2 is a north-south diagrammatic section across the NSB block and demonstrates generalized stratigraphic units. Economic basement in this area is slightly altered dolomites and argillites of Mesozoic or early Tertiary age. Altered granite was encountered in the Dl well. The basement ranges from a depth of 16,000 feet at the southwest comer of the NSB block to less than 4,000 feet near the Indonesia-Malaysia international boundary. Basement topography is generally smooth to gently undulating with north-south high trends formed by fault scamps. Sediments directly overlying basement consist predominantly of calcarenites and calcareous sandstones of the lower-upper Miocene Belumai Formation. These sediments show very little deformation except for regional dip to the southwest, and moderate drape over basement highs. Numerous pinnacle and biohermal reefs are present within the Belumai Formation. These reefs, developed present within the Belumai Formation. These reefs, developed on basement or Belumai highs, are given the local name Malacca Member. As seen in the stratigraphic section, the Belumai Formation with its Malacca reef developments is time-transgressive onto the Sunda Shelf. Ratios of Sr87 to Sr86 show the age of Malacca/Belumai carbonates to range from 7 to 23 million years. The Baong Formation overlies the Belumai/Malacca units in most of the area. It is a dark-colored shale and forms an effective seal for the underlying carbonate reservoirs. Downdip, at depths greater than about 8,000 feet, the Baong shale is considered to be a hydrocarbon source for both oil and gas. A thin bed of sandstone is present within the Baong Formation over much of the area and contains oil and gas in local closures. Keutapang, Seurula and Julu Rayeu sands and shales comprise the rest of the Stratigraphic column. These units display only monotonous regional dip to the southwest, being too far north to be affected by tectonic activity related to the Barisan Orogeny. These three formations together range in total thickness from 4,000 feet to 10,000 feet. Updip, where the Baong Formation is missing, lower shales of the Keutapang Formation serve as a seal for the Malacca reefs. A thin sand in the middle Keutapang contains gas and condensate at the 'A' field. Exploration History The NSO block, originally some 7.9 million acres in size, was awarded to Mobil in 1968. Subsequent relinquishments reduced the acreage to its present size of 3.2 million acres. A boundary dispute with Malaysia also served to rearrange the acreage; the NSO Extension block was assigned to compensate for acreage lost in the boundary settlement. The NSO block in its final form comprises 3 disconnected segments, of which the NSB area is one. Prior to 1979 seismic control consisted of 3,970 km of fine on a Prior to 1979 seismic control consisted of 3,970 km of fine on a grid spacing averaging about 2 × 4 km in the NSB area of interest. Up to that time, five wells were drilled including NSB-Al, a Malacca gas discovery made in 1972. In late 1979 the results of 2 wildcat wells, and some new seismic, revealed that literally dozens of pinnacle reefs were present.
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Greater Stella Area > Block 30/6a > Stella Field > Stella Ekofisk Formation > A2 Well (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Greater Stella Area > Block 30/6a > Stella Field > Stella Andrew Formation > A2 Well (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Greater Stella Area > Block 30/6-2 > Stella Field > Stella Ekofisk Formation > A2 Well (0.99)
- (4 more...)
The paper describes two innovative concepts. Firstly, the combining of all 4 main functions of an offshore production facility into one unit being:production gathering processing, treating and gas disposal storage measurement and transportation (terminating) The Floating Production Storage and Offloading System (FPSO) for Cadlao field in the Philippines combines all of these functions into a single tanker based unit. The development of this production system requirement system required the application of existing operating experience together with new component deign and applied research effort for specialized system features. The secondary conceptual, but important consideration, is the ability to lease such an integral system. The leasing concept introduced opens a new economic potential. It also initiates a new facet to the offshore oilfield service potential. It also initiates a new facet to the offshore oilfield service industry by joining the existing major contract services market such as drilling, offshore construction, supply boats and tugs, etc., Amoco Philippines Petroleum Company, the operator of the Cadlao field, and Terminal Philippines Petroleum Company, the operator of the Cadlao field, and Terminal Installations, Inc., the owner of the FPSO, have entered into a leasing arrangement for an integrated FPSO. Introduction The FPSO concept applies to those potential offshore production developments where any of the following pre-requisites need to be met:extended reservoir evaluation, utilizing production data, prior to full field development limited, remote or underdeveloped shore facilities early generation of revenues development of an area containing a single or multiple of small reservoir(s) This paper describes the development of the above concepts into a real system; an integrated floating, production, storage and offloading system for the Cadlao field provided on a lease basis. The integration of the production gathering and processing equipment onto a 125,000 DWT vessel moored in 300 feet of water and closed coordination and cooperation of the two classification societies involved. Lloyds and ABS, Overall system design approval was obtained. Major system components are described. Special attention is given to those sub-systems containing the result of innovative work which was necessary to meet both conceptual requirements of providing the four production faces and be leasable. The concepts of leasing the FPSO and the structure of the lease is reviewed briefly. Selection Of The Offshore Production System Once oil is discovered at an offshore location, the company must consider the best overall development scheme for most cost effective exploitation of the reservoir. The different basic development schemes which a company can use to develop offshore oilfields are: Fixed platforms utilizing pipelines to transport oil to shore based storage. Movement of oil from storage to market would be by means of onshore pipelines by a tanker loaded at a shoreside dock or by a tanker loaded at an offshore terminal (usually an SPM). Fixed platforms using offshore storage and export terminal. The most common scheme for storage utilizes a tanker with either rigid yoke mooring, or an SPM with soft mooring, for storage. Export of the oil is accomplished by shuttle tankers loaded directly from the storage tanker or by alternating tankers (such as the Montrose field in the North Sea). In some cases, oil is loaded onto a shuttle tanker moored to a separate SPM. Floating production systems include the use of semisubmersible rigs or tankers. The use of a semisubmersible rig requires subsea completions and a moored tanker for storage. The system which integrates production, storage and offloading into a single unit utilizes a tanker with a rigid yoke mooring permanently anchored at the location. This system, known as FPSO, is a relatively new concept which offers several advantages discussed later in this paper. The FPSO receives production directly from the wells paper. The FPSO receives production directly from the wells which can be completed subsea, on wellhead platforms or wellhead jackets.
- Asia > Philippines > Palawan > West Philippine Sea (0.85)
- Europe > United Kingdom > North Sea (0.54)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/18 > MonArb Field > Montrose Field > Upper Forties Sandstones Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/18 > MonArb Field > Montrose Field > Sele Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/17 > MonArb Field > Montrose Field > Upper Forties Sandstones Formation (0.99)
- (2 more...)
Offshore structures towed to a job site must be launched and upended (see Fig. 1). 1),2). In relatively shallow water, a structure is upended by hoisting it with a derrick crane. In deep water, however, a structure (usually large and heavy) is often self-upended without the aid of a crane, through buoyancy adjustment. There are two important factors involved upending procedures: the stability of the structure being upended, and the time-dependent change in the attitude of the structure. A computer program was developed to systematically analyze the stability of a structure being upended. The upending of a hydraulically unstable structure was analyzed by this program and, as a result, a safe upending procedure has been determined. procedure has been determined. A flooding analysis method has been developed for the time-dependent attitude change. This method analyzes the time-dependent change in the surface of water flooded into a structure's flood tanks. An actual jacket structure was analyzed by the method, and the analytical results are reported in this paper. Introduction To outline the upending analysis, the flow chart of the computer program INSTAN is shown in Fig. 2. This program was developed program INSTAN is shown in Fig. 2. This program was developed to analyze various on-site operations, including launching and upending. NFLOAT analyzes the natural floating conditions of a structure and its stable floating attitude at every stage of the upending operation. It also calculates the righting moment about the pitching and rolling axes of an offshore structure in order to evaluate its stability. UPEND, which was originally intended to evaluate crane-aided upending procedures, includes three-dimensional analysis sub-programs: POSITION and TENSION, both of which analyze upending by controlling hoisted loads and hook positions; and ROTATION, which controls a structure so that its tilting angle is constant. Another program, which evaluates the time-varying flooding height in the tanks, is also used in conjunction with INSTAN. Evaluation of Stability When a structure has little restoring ability during upending, rotational moments due to waves, winds and currents can cause sudden rotation of the structure, resulting in an accident. To avoid such misfortunes, stability checks must be conducted. Calculation of Righting Moment Righting moment (MR) is determined by calculating the unbalanced moment that occurs when the sea surface tilts relative to a certain angle ( ), as expressed in Eq. (1). where Wo = unit weight of sea waterxi = x-horizontal distance of i-memberyi = y-horizontal distance of i-member= pitching angle= rolling angle ..............(1) zo = relative vertical coordinate of sea surface dsi = area if i-member The relative vertical coordinate of the sea surface (zo) is determined from the conditions of balance between the buoyancy and negative buoyancy of the submerged portion of a structure. The righting moment about the rolling axis, MR( ), is also calculated by Eq. (1). Stability Curve The righting moment for a large heeling angle generally assumes curves such as the one shown in Fig. 3. It is clear from Fig. 3 that the stability of a structure increases as the distance between the stable balance point and the unstable point increases. Fig. 3 also indicates that the higher the peak value of righting moments, the more stable the structure. Improving An Upending Procedure For Hydraulically Unstable Structures Here an improved upending method will be presented - a method that begins flooding prior to the crane operation. According to the conventional upending method, a free-loading structure, after launching, is first hoisted by crane, then partially flooded, and finally tilted to an upright position. With the improved method, flooding starts prior to crane work, thereby giving stability to the structure before the structure is finally lifted. The difference between the two methods is the time at which the flooding operation begins, as shown in Fig. 4. Fig. 5 compares the stability of a structure at stage 2 of each method, while Fig. 6 compares it at stage 3. These data indicate that the flooding/hoisting method offers the following advantages over the hoisting/flooding one: . No unstable condition exists . The magnitude of righting moments increase continuously. A structure is, therefore, more stable when upended by the flooding/hoisting method.
This paper tells the story (in abbreviated form) of the evolution of the Hutton Tension Leg Platform (TLP) design from the preliminary stage through the preparation of the detailed plans, specifications, and other construction and installation instructions to builders, vendors and operators. An account is given of some of the problems encountered and their solutions. Planning and organization of the management of the project design activity are described. The design is presently being fabricated and will become the first large-scale realization of a development system which can be used in much deeper waters. Introduction When Conoco and its partners decided to develop the Hutton Field with a Tension Leg Platform (TLP) it was with a keen appreciation that the design, construction, and installation of this new system would present problems to challenge the resourcefulness of the project team and their associated contractors. project team and their associated contractors. By developing the Hutton Field, which is located about 90 miles northeast of the Shetland Islands beneath 148 m deep water, with a TLP it was intended to demonstrate the practicality of the concept and thus open opportunities for development of fields in still deeper water. This paper provides an account of most of the evolutions in the path to final Hutton TLP design, including problems encountered and their solutions. The Hutton design programme allowed extra time for design, recognizing that new system features would take longer than normal to complete. Nonetheless, the schedule could only be adhered to by an early design freeze and an intense design effort with strict design change control. Preliminary design work for the Hutton TLP attempted to adopt Preliminary design work for the Hutton TLP attempted to adopt design solutions by combining successful prior practices. Prudent system development, even for a new system, involves synthesizing concepts, components and configurations for which there is some related service experience. The size and scope of the new design has, however, led to some key components being altogether novel and others requiring extensive development from prior state-of-the-art. This applies particularly to the mooring and well systems. Design practices for an innovative system tike the Hutton TLP are based practices for an innovative system tike the Hutton TLP are based largely on fast-principles rational methods which require more diligent engineering interpretation than established practices which may be applied to conventional configurations. Although some elements of the design were closely related to prior practice (for instance, for the semi-submersible hull) detailed design methods were developed as a first-time effort of this Hutton design group. Before describing the evolution of the final design some features of the pre design will be reviewed. Also a brief explanation of the Conoco project management approach will be given, highlighting project design activities. Preliminary Design Preliminary Design 2.1 Background The TLP is a floating structure connected to anchors fixed in the seabed by vertical mooring lines (tension legs) at each comer of the platform. These vertical mooring lines virtually eliminate the vertical plane motions of heave, pitch and roll while the lateral movements in surge, sway and yaw are compliantly restrained. Buoyancy is provided by the vertical columns and the connecting horizontal pontoons connecting the bottom of these columns. An excess of buoyancy which is greater than the platform weight keeps the mooring lines in tension for all weather and loading conditions. The TLP concept was introduced in the 1960's and many study and development programs have examined its use in deep water oil developments. An important step in the conceptual development of TLPs was made in 1975 with installation of a small version of a TLP offshore California by Deep Oil Technology. This 635 tonne platform was set in 200 ft deep water and collected data during a six month trial period. This test provided practical information on responses period. This test provided practical information on responses to winds and waves such as mooring loads, platform motions, riser stresses and other data which could be compared with design predictions. At about the same time, a team of Conoco engineers were analysing subsea production systems for deep water. They recommended that designs should be developed to provide above water platform space to accommodate drilling and production facilities in deep water. The tension leg platform production facilities in deep water. The tension leg platform was recognized as a prospective system with costs that should be relatively insensitive to depth of water. An intensive study concluded that this concept was feasible and could be designed to be reliable. 2.2 Design Description With this background, Conoco and its partners carried out an in-depth preliminary design of a tension leg platform specifically for the Hutton Field. Many of the key conceptual design premises were established at this time, including that the deck will be built separately as an integrated assembly to be mated to the hull in sheltered waters. All components will be designed for a minimum of 20 years service life. Key components such as tension legs and well riser tensioners will be simple and intrinsically reliable, have backups, and will be replaceable for inspection and maintenance. Individual well risers connect each well to the TLP. The TLP is permanently installed in the sense that it can resist the effects of extreme environmental conditions and continue operations in the same manner as conventional fixed platforms. This Hutton TLP preliminary design was described to the European Offshore Petroleum Conference in London in October 1980 (Ref. 1). Only a brief description of this design will be given here, together with some background information on TLPs in general to facilitate the account of design evolution and to identify key features of the TLP. Figure 1 illustrates both the preliminary and final designs.
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > PL 123 > Block 211/19 > Murchison Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/28 > Hutton Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/27 > Hutton Field > Brent Group Formation (0.99)
The paper will first give a brief summary on the technological developments of offshore loading systems and a prediction of future trends and challenges. Based on previous studies of several different design concepts, the paper will deal with the methods applied in the analysis and factors contributing to the unavailability of offshore loading systems. The following categories are discussed:–Environmental factors limiting the availability of the plant, –Structural failures, non-scheduled repairs and inspection. –Process system and operational failures and the associated repair, causing off hire. The result of the availability analysis will be identification of components and conditions contributing to availability. It will be shown how the knowledge in turn can be utilized in formulating redundancy and more specific design related criteria and guiding inspection and maintenance during operation. The use of the analysis in evaluating relative value of different design solutions will be discussed. The last part of the paper will give specific guidance and recommendation on design, fabrication and operation of offshore loading system based on many years of involvement in all phases of offshore loading systems, i.e. -research-conceptual evaluation-certification-in-service inspection-rule and guidance development. Introduction In October, 1981, the Norwegian government approved the initial development of today's most prosperous oil field on the Norwegian continental shelf the so-called "Golden Block". With estimated reserves of 200 mill. tons of oil corresponding to a present value of US $48 billion, the reserves must be denoted as considerable by any standard. The transport alternative for the shipment of oil from this source, located in the harsh environment and deep waters of North Sea, will be through two offshore loading systems (Fig. 1.). Rather than representing the frontiers of utilization of today's offshore loading systems, these may be considered as typical applications. The twenty years of development within offshore loading might therefore be regarded as remarkable. Historical Development Single-point mooring terminals have been developed over the years as a means of mooring large vessels for offloading or loading bulk cargoes without building complex port facilities. Lately their use has been extended to the export of crude oil from offshore oil fields, especially in hostile and deep environments such as the North Sea. The principle common to all Single Moorings (SPM) in use today is that a shuttle tanker is moored to a permanent buoy by a braided synthetic rope or ropes as its bow. From a seabed pipeline, the product is discharged through a riser pipe or hose pipeline, the product is discharged through a riser pipe or hose to a swivel assembly at the buoy centre. A turntable or super-structure supporting pipework and mooring attachments, connects the swivel with flexible hoses which extend to the tanker's manifold system. In addition to product hoses, lines for ballast water, bunkers or pipeline flushing return may be fitted. A wide range of buoys have been installed and the different types of terminals are mainly recognized by the anchoring system. The first generation and more simple floating terminals are fixed to the seabed by several chains and load onto the shuttle tanker through a floating hose. These simple buoys will normally not achieve the desired reliability in a hostile environment and deeper waters. Structures more resistant to adverse weather conditions, such as articulated towers., are here required. An articulated tower is "anchored" to the seabed by a universal joint which allows angular movements in all directions. Typical examples of today's generation is shown on Fig. 2, comprising. Catenary Anchor Leg Mooring CALM, which is the traditional and most widespread offshore loading buoy. The first CALM design was installed in Dalaroe in Sweden in 1959. In the North Sea, the CALMs installed in the Ekofisk area in 1971 ensured the supply of oil from the first commercial oil field on the Norwegian shelf. The pipeline end manifold is connected to the buoy by flexible hoses. The tanker is free to weathervane 360 deg around the buoy connected with a blow hawser. Crude oil is transferred from the buoy to the tanker via floating hoses.
- Europe > United Kingdom > North Sea (0.75)
- Europe > Netherlands > North Sea (0.66)
- Europe > Denmark > North Sea (0.66)
- Europe > Norway > North Sea > Central North Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.34)
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
- Europe > United Kingdom > North Sea (0.54)
- Europe > Norway (0.48)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/28 > Hutton Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/27 > Hutton Field > Brent Group Formation (0.99)