Batten, C.J., Woodside Offshore Petroleum Pty. Ltd. (Australia)
This paper describes experience with respect to underwater work carried out by Remotely Operated Vehicles (ROV's) on the North West Shelf Development Project, North Rankin 'A' field located 135 km off the North West coast of Australia. The field is operated on behalf of the joint venturers by Woodside Offshore Petroleum Pty Ltd. Installation of the platform and trunkline was completed in 1982 and from this date all underwater work has been carried out by ROV. Typical work includes detailed pipeline and platform inspections, underwater support for the installation of gravity anchors and associated guy wires, general construction, support, underwater cutting, marine fouling removal, scour protection installation and pipeline stabilization.
Information presented in this paper is applicable to all phases of offshore oil and gas production that requires work to be done underwater e.g. exploration drilling, construction, operational inspection and maintenance. The paper describes special tooling procedures and systems developed to perform the above work. Also presented are new information and statistics associated with bulk marine fouling removal by purpose designed/built remotely operated equipment.
The paper concludes that significant underwater work can be performed cost effectively without exposing men to risks associated with the underwater environment and shows that a much larger slice of the underwater work "pie" can be achieved by ROV than has previously been generally accepted.
Specific data related to time/costs associated with performance of significant aspects of the work are presented.
This paper describes the experience gained by Woodside Offshore Petroleum Pty Ltd in the application of underwater remote technology on the North West Shelf Development Project, North Rankin
A field. This field is operated north behalf of the North West Shelf Development Project joint venturers by Woodside and is located in a remote area 1000 miles north of Perth and approximately 135 km off the North West Coast of Australia.
The North Rankin 'A' field was the first offshore oil and gas field to be developed in this area. At present the offshore development is comprised of one offshore steel jacket gas production platform (North Rankin A) in 125m water depth and a 1 metre diameter trenched pipeline to shore. Installation of both facilities was completed in 1982. Since that time all underwater inspection, maintenance and repair activities associated with these facilities and underwater construction support for the North Rankin A remedial foundations work has been successfully achieved using remote underwater technology.
This paper includes a brief description of the technology that has been utilised or developed to date followed by a presentation of operational cost data illustrating the cost effectiveness of remote technology when , compared to diving for significant aspects of the work.
Woodside currently owns and contracts the operation and maintenance of three remotely operated vehicles (R.O.V's). These are comprised of one 100 hydraulic HP general purpose work type vehicle (Triton), a smaller inspection and limited work type vehicle (RCV 150) and the recently developed special purpose marine growth removal vehicle (Scimitar). The vehicles and their basic configurations are shown in Figure 1. Each vehicle has it's own Launch and Recovery System (LARS) consisting of an A-frame and winch, a Tether Management System (TMS) for managing cable payout and a surface control module.
The vehicles can be configured with a range of tool packages developed by or for Woodside for specific applications.
Kip, S.H., Sarawak Shell Bhd/Sabah Shell Petroleum Co. Ltd. (Malaysia)
Oil spill contingency planning is an essential feature required in present day activities involving oil and gas exploration, production and transportation. A well thought out Contingency Plan will not only eliminate or minimise the sense of panic, normally associated with oil spill emergency, but also can minimise damage and cost involved.
Simply put, oil spill contingency planning is a process of predetermining a response to an oil spill emergency. The process of preparing a contingency plan varies but the final plan is normally produced into a document, to be followed in an oil spill emergency. With this document prepared and agreed by all concerned parties, the approach and response to an oil spill should be more organised. It is also generally accepted that an organisation with the necessary contingency plan in place is better prepared to handle an emergency that one without a contingency plan.
Oil spill contingency planning is a feature of Shell Group policy. Sarawak Shell Berhad (SSB)/Sabah Shell Petroleum Company Limited (SSPC) produced an Oil Spill Contingency Plan in 1978 which has undergone a number of modifications and updates. Drills and exercises are also conducted with a view to improve the company preparedness to tackle oil spill emergencies.
SSB/SSPC is the main oil and gas exploration and production company operating offshore in the Malaysian states of Sarawak and Sabah. With an average production level of approximately 200,000 barrels of oil per day. Shell produces about 45% of Malaysia's total crude oil production.
All or the Company's producing oil and gas fields and concession acreage are situated offshore. Currently it operates 27 production stations offshore which feed into the crude oil terminals in Bintulu, Lutong and Labuan. The geographical spread of more than 600 km between the northern most field and the southern most field provides an extensive coverage for oil spill contingency planning.
Sarawak and Sabah coastline runs in the northeast - southwest direction with the South China Sea in the north and land to the south. The production stations offshore are generally between 15 to 100 km from the shoreline. General weather variation is affected by the Northeast Monsoon from November to February and Southwest Monsoon from July to September with October a transition month and March to June generally calm. Currents are not generally strong except at specific locations, caused by unusual bottom topography.
In Malaysia, the spiller is responsible to tackle and cleanup an oil spill. However, the government via the Marine Department of the Ministry of Transport and the Department of Environment, Ministry of Science Technology and Environment can be requested to assist or can intervene in an oil spill emergency. The government can in turn recover the full cost of its cleanup operation from the responsible party.
FEATURES OF THE PLAN
Like any other Company's procedure document. the Oil Spill Contingency Plan is required to be fully discussed within SSB/SSPC, agreed by relevant parties and approved by senior management. This is because it establishes the authority to take oil spill control measures.
The Plan has also received the relevant concurrence of the Malaysian National Oil Company (PETRONAS) and the Department of Environment.
Lessons learnt from previous experience are incorporated into subsequent updates of the plan. Most of the features that can be considered as "unique" in the contingency plan evolve from in-house experience.
Development of the Central Luconia gas fields, located offshore Sarawak, started in 1982. To data three gas fields have been developed, E11, F23 and the third and largest gas field, F6, which came on stream in January 1987. The daily production rate averages some 1000 MMscf/d.
The gas is delivered via a single 36" trunkline from E11 to the Malaysian LNG liquefaction plant for the Manufacture of LNG at approximately 6 million tonnes per year for a period of 20 years. Gas is also distributed to the ASEAN Bintulu Fertilisation plant for the production of urea and ammonia, and to Sarawak Electricity Supply Corporation for power generation.
This paper describes the 3D simulation study that has been carried out for the F6 field which forms the basis for the development planning of the field. The plan proposed a total of ten producer and one observation well to be drilled from the drilling platform F6DP-A located near the crestal part of the field.
Despite the large reservoir areal extent of about 168 km2, it is expected that the field can be adequately drained from a single platform with ten producers.
The main uncertainties which may affect the field performance are the transmissibility of a tight argillaceous layer which may separate the gas bearing part of the field into two zones and the possibility of water drive. The likely impact of these uncertainties on the development plan and gas recovery has been addressed in the simulation study.
Taking the above uncertainties into consideration, recovery factors are estimated to be between 61% and 75%.
The Central Luconia province is situated some 100 miles offshore Sarawak. Malaysia in 230 - 290 ft of water (Fig. 1). During the late 1960's, Sarawak Shell Berhad (SSB) carried out exploration drilling in Central Luconia. Numerous gas accumulations were found in carbonate buildups and the gas reserves were evaluated to be large enough for a viable LNG scheme. Proposals were presented to the Malaysian government in 1971, which eventually led to the formation of Malaysian LNG Sendirian Berhad (MLNG) in 1978. Petronas (the Malaysian national petroleum company) took up 60% equity in this venture, while Shell Gas B.V. and Mitsubishi Corporation of Japan took up 17.5% each, and the State of Sarawak 5%.
Central Luconia gas is further distributed to the ASEAN Bintulu Fertiliser plant for the production of urea and ammonia, and to Sarawak Electricity Supply Corporation to generate power for local use.
The results of seismic surveys taken during the mid - 1960's indicated the possibility of large carbonate structures in Central Luconia. Exploration drilling in 1968 confirmed the existence of these carbonate structures. The first significant gas accumulation was discovered by well F6.1X in 1969. Exploration drilling in 43 carbonate structures within the period 1968-1975 led to the discovery of 20 gas accumulations, of which 10 contained significant quantities of non-associated gas.
Appraisal drilling in the five largest gas fields, E11, F23, F6, ES and F13, which are committed to the LNG project. was completed before end 1978 to better define geology, reserves, productivities and wellstream compositions.
E11 was the first gas field to be developed, being closest to shore. By 1982, the installation of offshore platform and associated facilities, and the 78 miles long 36" trunkline to shore was completed.
This paper reviews Mobil Oil Indonesia's experience in the completion of high temperature, high rate gas wells, gained during ten years as operator for the Arun Field.
Over 50 production and injection wells have been completed in the Arun Field, and some of these wells have been worked over once or even twice since their initial completion. problems which have been encountered during the operation or workover of the wells have led to changes in completion practices and equipment design. These problems are described in detail as are the subsequent completion changes and the results of these changes.
The Arun Field is a giant natural gas condensate field located in Aceh Province at the northern tip of the island of Sumatra (figure 1). It was discovered in 1971. Mobil Oil Indonesia (MOI) is the operator for the field, acting as a production sharing contractor to the Indonesian national oil company, Pertamina. The field is a major source of LNG for Japan and Korea.
Abnormally high producing temperatures and pressures, the corrosive constituents of the well stream fluid, and high field production rates, have combined to present many challenging engineering and operating problems. Individual Arun wells are capable of production rates in excess of 150 MMSCF/D with wellhead temperatures above 300F. The initial reservoir pressure was 7100 psia and wellhead producing pressures were 5500 psig or greater.
As a consequence of these extreme conditions, the original Arun completions developed wellhead seal and tubing connection leaks. A comprehensive design review, including laboratory testing, identified the mechanism by which leakage occurred. An alternative completion design was then developed based on metal to metal wellhead seals on the final cemented casing, and premium shouldered connection tubings with multiple seals. New Arun wells were completed in this way and a workover program was undertaken to recomplete all wells which had the original completion.
The Arun Field workover program indicated that the weighted invert emulsion packer fluid resulted in solids settlement and emulsion breakdown. Extensive investigation eventually led to the specification of an unweighted refined oil as a suitable replacement packer fluid.
The workover program further showed that the seal assembly in every polished bore receptacle (PBR)/seal assembly type of completion was firmly stuck in the PBR. No seal assembly was pulled in any of the 29 workovers. A testing program was initiated to determine if a packer type completion with a rigid tubing to packer connection would be suitable for Arun usage. Subsequently an hydraulic set packer was specified.
II. THE EARLY ARUN COMPLETION DESIGN
The first Arun well to be drilled and completed as a development well was CIII-2 (A-15), in January 1977.
The well was completed as shown in figure 2, and included many of the features typical of the early Arun completion design. Features which should be specifically noted are as follows:
o Resilient elastomer seals were used on all wellhead casing packoff sealing systems with only the tubing; hanger neck seal incorporating a metal to metal seal.
o A premium thread tubing connection with limited back-out resistance was specified.
o The production tubing downhole isolation assembly was the PBR/seal assembly type with the PBR being run as part of the 9 5/8 inch cemented casing.
o A weighted invert diesel water emulsion was used as the packer fluid in the 7 inch by 9 5/8 inch annulus.
It became evident after some operating experience had been gained that this type of completion was not suitable for Arun producing conditions. The problems encountered will be discussed in the following sections.
Huffco Indonesia has developed and installed a computerized database system called PARM System - Production and Reserves Monitoring System. This integrated database handles data that includes reservoir, geological, production, operations and mechanical well data. while the PARM System data are acquired and controlled from many technical and operations disciplines within the it is always input as close to the original source as possible.
The PARM System, as an integrated production and reserves data source for Huffco Indonesia, has applications across a wide range of engineering and operations disciplines. Daily production and operations reports, monthly production allocation and product distribution reports, daily drilling reports and summary reports and many other necessary routine reports are. generated by the PARM System. Benefits of analysis of large volumes of data, which were previously very cumbersome to attempt, are now being realized by engineering groups. Ad-hoc data retrievals provide consistent current and historical data for production and reservoir engineering applications.
An integrated computerized database system such as the PARM System, provides a cost and time efficient engineering and operations tool. It provides unparalleled accessibility to any data likely to affect or resulting from the oil and gas production of a well, zone or field. Accuracy of original data is improved due to multi-user review and built-in integrity chocks. Development of a system, such as the PARM System, should be done on a prototype basis under direct engineering management.
Application of computer technology to the petroleum industry is manifested in the PARM System by virtue of capturing and handling of the basic oil and gas operations and engineering data. This paper describes the design and implementation concepts of the PARM System as well as engineering and operations applications ranging from simple reports and data retrievals to interfacing with reservoir simulation software.
Huffco Indonesia is the operator of an oil and gas Production Sharing Contract (PSC) area in East Kalimantan, Indonesia.
Wells in the PSC area currently range to 15,000 feet in depth with producing horizons being completed in various intervals between 1000 feet to 12000 feet. In one of the four currently producing fields, Badak, there are more 200 unique zones. Producing and producing fields have a total of 336 wells. Many of the wells in the producing fields have dual or multiple completions with some having commingled zone production. while the four currently producing fields produce approximately 37000 barrels of oil and condensate per day, the major production is natural gas where the capability is in excess of 1 billion standard cubic feet per day. The natural gas production, after processing at the respective fields, is supplied to the Bontang LNG plant where it is liquefied and utilized to fulfill contracts with offshore buyers. With firm long-term contracts in effect, it is imperative that the supply be able to meet the demand. To insure that this criterion is maintained it is essential to have an accurate, current, accessible database of the various parameters affecting the ability to supply.
Huffco, with consulting assistance, performed project definition and planning study which aided in defining objectives and the philosophy of operation of a Production and Reserves monitoring System.
In assessing the large volume of interrelated data to be handled the objectives of Production and Reserves Monitoring System were defined to be as follows:
- Provide timely common access to basic data for performance monitoring. Under the existing system considerable time could pass before basic data such as well tests, would reach personnel responsible for monitoring and analysing well performance.
- Minimize redundancy of information handling, transcribing, summarizing and copying of data resulting in time loss and frequent data transcribing errors.
This article gives a preliminary analysis of the impact of application of horizontal drilling and production techniques on the economy of offshore reservoir developments.
If we consider wells with a medium and long radius of curvature ensuring horizontal drilling in reservoirs with horizontal sections of greater than 300 m (1000 ft), theoretical research shows that flow ratios of four or more can be obtained in practice in practically all reservoirs, provided they are vertically permeable ana no more than 60 m (200 ft) thick. These theoretical results agree well with what is observed in the field.
Analysis of the data available on horizontal drillings performed so far shows that offshore, the cost per metre drilled in a horizontal well tends with experience towards the cost per metre drilled in a conventional well. The excess cost of a horizontal well is essentially due to the greater length drilled.
Offshore, the capital and operating costs bear an increasing relationship to the number of wells and production level. From a model of these costs based on 28 projects in the North Sea, the impact of replacing conventional wells with horizontal wells was studied. In the case of complete development, the reduction in the number of wells for the same production flow enables the technical cost of the oil to be decreased by 2 to 8 dollars per barrel, depending on the case. The parameters of importance are firstly, the ratio of the flowrate of the horizontal well to the flowrate of the conventional well, secondly the ratio of the cost of drilling to the total cost and thirdly the flowrate of the conventional reference well.
Cases of application yielding the greatest savings are those where the share of drilling costs out of the total cost is high, over 25 ana cases where the flowrate of conventional wells is low, below 2000 Bopd.
Drilling and bringing into production horizontal wells has been growing considerably since the beginning of the 1980s. Originally restricted to technological operations and subsequently to pilot projects, horizontal drilling is now being applied to complete developments of offshore fields. Development of the Rospo Mare reservoir in Italy by Elf, Unocal operations in Dutch waters in the North Sea, Arco in Indonesia, Standard Oil (ex Sohio) in Alaska, where the situation can be assimilated to an offshore situation, all bear witness to the fact that horizontal drilling has now come of age.
If one excludes a few operations for essentially technological purposes with a view to gathering know-how, trying out new techniques or involving applied research, the great majority of horizontal wells have been drilled offshore (see figure 1). Why ? for mainly economic reasons, since there is no production-related reason that dictates that an offshore reservoir is a better case of application than an onshore reservoir. From the drilling standpoint, it can be said that offshore, the habit of drilling deviated wells has provided a foundation on which horizontal drilling can rest, though cost factors are the main motive.
Completion operations, for oil and gas wells, are usually performed in casing sizes not exceeding 13-3/8" (34.0 cm) with the majority of completions being performed in 9-5/8" (24.5 cm) and smaller. As such, the availability of completion equipment, for large diameter casings, becomes extremely limited or nonexistent, Occasionally, conditions may exist which require the completion to be designed in a casing size larger than 13-3/8" (34.0 cm). In order to complete in these casing sizes, special equipment must be designed.
This paper discusses the design criteria, development, and subsequent use of perforating and gravel pack equipment generated for use in 20" (50.8 cm) casing. The theoretical approach to the evolution of this equipment is applicable to the development of additional systems.
While completion equipment is largely designed for 9-5/8" (24.5 cm) casing sizes and smaller, with some equipment available up to 13-3/8" (34.0 cm), perforating and gravel pack equipment is virtually nonexistent in sizes greater than 9-5/8" (24.5 cm). Due to specific well completion requirements it may be advantageous to be able to complete in the larger diameter casing sizes. With equipment being unavailable for these larger sizes, special equipment must be developed.
The herein discussed completion system has been specifically developed for 20" (50.8 cm), 133 lb/ft (198 kg/m) casing. In this application a very shallow, low pressure, gas zone exists beneath a platform. It is the operator's intent to set 20" (50.8 cm) casing across the zone and attempt to blow down the gas. Following depletion of the zone, the 20" (50.8 cm) wellbores can be cleaned out and deepened to the primary objective zones. Further development drilling could then commence with less risk and lover costs.
With the primary objective of the project being the depletion of the reservoir, the resultant completion had to be installed in the most efficient manner possible. Owing to the less than 500 psi (3447.5 kPa) static reservoir pressure and the desire to deplete as quickly as possible, the perforating system had to deliver the highest shot density possible with the greatest amount of charge performance. This would provide for the maximum flow rate by minimizing pressure loss through the completion. A systems analysis plot, Fig. 1, supports this and, thus, fostered the need of a specialized perforating gun.
Existing perforating equipment would have required multiple trips to achieve the desired perforation shot density, and would not have been able to offer positive, shot orientation. Performance would also suffer as clearance between the gun outside diameter and the casing inside diameter would have been difficult to control.
Consequently, a perforating system was needed that would offer a very high shot density with maximum performance, while affording positive shot orientation.
Due to the zone being gas, positive well fluid isolation and pressure containment became a criteria. This precluded the use of existing large diameter equipment, which typically have lead seals that are not capable of effecting a suitable gas seal. Additionally, the original design parameters called for the use of a retrievable seal bore packer as the perforating packer.
With the expressed desire to underbalance perforate, the requirement for positive gas pressure containment, and the need for secure casing anchorage, a special packer and associated gravel pack assembly was essential.
The paper describes EPMI's efforts to eliminate potentially catastrophic hydrocarbon liquid and gas discharge from the open drains of its platforms located offshore Peninsular Malaysia in the South China Sea.
The hydrocarbon discharges were largely precipitated by equipment failure and related events but were made physically possible by the use of a common discharge caisson by both the open and pressured drain systems.
For platforms containing major processing equipment, the modifications to separate the open drains from the pressured drains involve the installation of a second drain caisson. For other platforms, the systems were separated by returning the pressure drains discharge to the process stream. As a result of the described modifications, high pressure crude dumped to the drains even at very high flowrates cannot result in hydrocarbons to be discharged from the open drains.
All EPMI platforms have been modified and the installed systems are operating satisfactorily. EPMI now requires the complete separation of the pressured drains from the open drains in all its offshore installations.
Drain systems play a crucial role in the safe and environmentally acceptable operation of any offshore production facility. Efficient drain systems will allow produced fluids discharged from hydrocarbon process streams in a production facility to be safely disposed of. However, the failure of the drain system to perform as desired can result in safety and environmentally hazardous incidents.
Such failures of the drain system has resulted in incidents of hydrocarbon being discharged from the open drains on several EPMI platforms. These incidents were caused mainly by equipment failure and related operational events but were made possible by the physical use of a common drain caisson or the pressured process equipment drains and the open drains.
The modifications to the drain system of seventeen EPMI platforms are aimed at enhancing safety on the platform by providing a safe means of disposing produced fluids from the process stream. The retrofit work involves the physical separation of the pressured drains from the open drains. For the manned platforms, this was achieved with the use of a separate drain caisson for the open system. For the other unmanned platforms, discharges from the pressured drains are returned to the process stream.
Drain system modifications were successfully implemented on all the affected platforms. Installed systems are operating satisfactorily with no further incidents of hydrocarbon discharge from the open drains.
The US$3.1M spent for these modifications demonstrates EPMI'S commitment to provide safe and efficient facilities in all its operations.
EPMI has required the complete separation of the pressured and open drain systems with the use of dual caissons in all its offshore installations to ensure the elimination of hydrocarbon blowbacks and to allow the safe and efficient disposal of pressured produced fluids on its production facilities.
EPMI'S PRODUCTION FACILITIES OVERVIEW
Location (Figure 1)
EPMI operates twenty-two platforms, 200 km offshore the east coast of Peninsular Malaysia in the South China Sea. Of these, twelve platforms are manned. The remaining ten, including a pump platform, are unmanned. These platforms are installed in water depths which vary between 60m to 75m.
Crude production is gathered at the Tapis Pump platform a nd sent onshore to the Terengganu Crude Oil Terminal (TCOT) where it is stabilized, and stored and subsequently exported to tankers through near-shore SALMS.
Manned Platform Operations (Figure 2)
The manned platforms are eight-legged structures with typically 21 to 32 well slots. These platforms have integrated modularised drilling, production, flare, power generation and accommodation facilities.
Other facilities may include gas compression, produced water handling equipment and water flood equipment.
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.
The gas Gathering System, situated at both offshore Terengganu, in the east coast of peninsular Malaysia, comprises the following installations:
1. Duyong Gas Field Complex 2. Sotong Collector Platform (SCP) 3. 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:
1. Wellhead Platform A (WPA) 2. Wellhead Platform B (WPB) 3. Wellhead Platform C (WPC) 4. Central Processing Platform (CPP) 5. 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 X 10-6 Sm3/day to a maximum of 1.40 X 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 X 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.
The Seria field, onshore Negara Brunei Darussalam on the North Western coastline of Borneo, South East Asia, has been in production since 1930 and up to now some 34% of STOIIP has been produced by 760 wells. Ultimate Recovery, estimated from extrapolation of performance is 39% of STOIIP.
This paper outlines the approach followed in planning of infill drilling and presents recent experience for the Seria West (SW) block and three other blocks of field.
Infill drilling overall is expected to increase the ultimate recovery of the Seria field to 43% of STOIIP.
The Seria oil field onshore Negara Brunei Darussalam on the North Western coastline of Borneo in South East Asia has been in production since 1930. For production purposes the continuous range of crude gravities (15-42 API) is split into two types. Heavy oil from depths between 1000' and 4000'ss, containing 34% of the total STOIIP and light oil below 4000'ss with 66% of the total STOIIP. The reservoir oil viscosities average some 10 cP for heavy oil and 1 cP for light oil.
In the 55 years of field life 760 wells have been drilled, 34% of STOIIP has been produced and an ultimate recovery of 39% can be expected with the present wells and recovery methods, thus leaving 61% of oil in the reservoirs.
1.1 Reservoir Setting
The Seria field is situated on an East-West elongated asymmetrical anticline (Figure 2). There are two major culminations with a shallow saddle separating them. The North flank of the field and the saddle area between the culminations contain less significant quantities of hydrocarbons.
The accumulations which consist of many continuous sands, separated by shales, are in general heavily faulted (Figure 2). The reservoirs have historically been classified according to geological markers and each reservoir is of the multisand type. Production has been commingled from these multisand system.
The Seria field is subdivided in 92 blocks containing in total 522 oil and gas reservoirs of which many can be further subdivided into separate sand units. Some 210 reservoirs with STOIIP values above 2 MMbbl represent 94% of the field's STOIIP.
1.2 Basis of Reserves Estimate
Awaiting the interpretation of the recently acquired seismic data which covers most of the Seria field, current STOIIP figures are mostly based on the 1969 generation of structure saps. Modern log coverage exists only in wells drilled after 1972 (S-590). Moreover log derived water saturations are often different from those indicated by capillary pressure data. Although many STOIIP figures are substantiated by material balance calculations considerable uncertainty exists. Over recent years therefore, reserves have been largely derived by extrapolation of production performance data alone.
It is believed that the present approach to reserve estimation in the Seria field leads to a conservative estimate and that there still exist considerable amount of recoverable infill reserves.
1.3 Scope for Infill Development
The degree of commingled production combined with the stratified nature of the reservoirs suggests that considerable bypassing of oil may have taken place. This is confirmed by modern logs in recent wells and also by GST logging in old producers.